ny dec fracking regs combined document

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Revised Express Terms

High Volume Hydraulic Fracturing

A new Part 52 of 6 NYCRR is adopted to read as follows:

Part 52

Use of State Lands Administered by the Division of Fish, Wildlife and Marine Resources

(Statutory authority: Environmental Conservation Law, sections 1-0101, 3-0301, 11-0303, 11-0305, 11-2101,

45-0117)

52.1 Applicability

The provisions of this Part shall apply to all State lands under the Department’s jurisdiction that are

administered by the Division of Fish, Wildlife and Marine Resources, including but not limited to such lands

designated as wildlife management areas, multiple use areas, unique areas, natural resources management areas,

fishing access sites, boat launch sites, hatcheries, game farms and tidal wetlands.

52.2 Definitions

(a) Definitions. As used in this Part, the following words shall have the indicated meanings:

(1) ‘Department’ means the New York State Department of Environmental Conservation.

(2) ‘State lands’ shall mean all real property interests owned by the State of New York under the

Department’s jurisdiction that are administered by the Division of Fish, Wildlife and Marine Resources,

including but not limited to such lands designated as wildlife management areas, multiple use areas, unique

areas, natural resources management areas, fishing access sites, boat launch sites, hatcheries, game farms

and tidal wetlands.

(3) ‘Surface disturbance’ shall mean any actions taken to alter the existing vegetation or soil of a

site, such as clearing, grading, filling, and excavating.

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52.3 Prohibitions

Notwithstanding any other provision of this title, surface disturbance associated with the drilling of a natural gas

well subject to Part 560 of this Title on State lands is prohibited and no permit shall be issued authorizing such

activity. This prohibition shall apply to any pre-existing leases and any new leases issued for oil and gas

development on State lands. This prohibition shall not apply to subsurface access to subsurface resources

located under State lands from adjacent private areas.

52.4 Severability

If any provision of this Part or its application is held to be invalid, the remainder of this Part and the application

of that provision will not be affected.

Part 190

Paragraphs (14) and (15) of subdivision 190.0(b) of 6 NYCRR are renumbered as (15) and (16) and a new

paragraph (14) is added to subdivision 190.0(b) of 6 NYCRR to read as follows:

(14) ‘Surface disturbance’ shall mean any actions taken to alter the existing vegetation or soil of a site, such as

clearing, grading, filling, and excavating.

A new subdivision (ag) is added to section 190.8 of 6 NYCRR to read as follows:

(ag) Notwithstanding any other provision of this title, surface disturbance associated with the drilling of a

natural gas well subject to Part 560 of this Title on State owned lands is prohibited and no permit shall be issued

authorizing such activity. This prohibition shall apply to any pre-existing and new leases issued for oil and gas

development on State owned lands. This prohibition shall not apply to subsurface access to subsurface resources

located under State owned lands from adjacent private areas.

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Revised Express Terms 6 NYCRR Parts 550 through 556 and 560

6 NYCRR Part 550, Promulgation and Enforcement of Rules and Regulations

The title of Part 550 is revised to read:

[Promulgation and Enforcement of Rules and Regulations] General

Section 550.1 is unchanged.

Section 550.2 is amended to read:

(a) To carry out the functions outlined in section 550.1 of this Part, the Department of Environmental

Conservation has created a [Bureau] Division of Mineral Resources.

(b) The [Bureau]Division of Mineral Resources is headed by a [chief]director who is responsible for the

administration and enforcement of all rules, regulations, orders and amendments thereof of the Department of

Environmental Conservation relating to the exploration and drilling for, and production, transportation,

purchase, processing and storage of oil and gas and other wells regulated under Environmental Conservation

Law Article 23, and the prevention of any pollution resulting therefrom.

(c) The [chief]director of the [Bureau] Division of Mineral Resources shall be responsible for the

directing, supervising and proper performance of the Division of Mineral Resources.

(d) The [chief]director of the [Bureau] Division of Mineral Resources is aided by an assistant

[chief]director who acts in the former's absence. At those times, the assistant [chief]director bears both the

responsibilities and authorities of the [chief]director.

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(e) To carry out field responsibilities, the [Bureau]Division of Mineral Resources is organized into

several regions, each headed by a regional supervisor, who acts as the [chief’s]director's deputy in all relevant

matters.

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

Subdivision (h) of Section 550.3 is repealed, subdivisions (i) through (o) are re-lettered subdivisions (h) through

(n), and a new subdivision (o) is added to read:

(o) ‘Director’ shall mean the director of the Division of Mineral Resources of the Department of

Environmental Conservation.

Subdivisions (p) through (r) of Section 550.3 are unchanged, subdivisions (s) through (ba) are re-lettered

subdivisions (u) through (bc), and new subdivisions (s) and (t) are added to read:

(s) ‘Hydraulic Fracturing’ or ‘Fracturing’ shall mean a stimulation technique involving the pumping of

hydraulic fracturing fluid, possibly with a proppant, into a formation to create fractures to increase formation

permeability and productivity, but shall not include other operations during a workover.

(t) ‘Hydraulic fracturing fluid’ shall mean fluid used to perform hydraulic fracturing and includes the

base fluid and all applicable additives.

Newly re-lettered subdivisions (ay) through (bc) of Section 550.3 are relettered (ba) through (bf), and new

subdivisions (ay) and (az) are added to read:

(ay) ‘True measured depth’ shall mean the total distance from a depth in a planned or existing wellbore

or well to a point at the surface measured along the existing or planned wellbore or well.

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(az) ‘True vertical depth’ shall mean the vertical distance from a depth in a planned or existing wellbore

or well to a point at the surface.

Newly re-lettered subdivision (bf) of Section 550.3 is relettered subdivision (bh), and new subdivisions (bf) and

(bg) are added to read:

(bf) ‘Well spud’ shall mean commencement of driving, drilling or other installation method to set the

requisite amount of conductor or surface casing.

(bg) ‘Workover’ shall mean any downhole operation in an existing well performed after initial

completion that is designed to sustain, restore or increase efficiency, make the well safer, or correct a known or

potential environmental hazard.

Sections 550.4 through 550.7 are unchanged.

6 NYCRR Part 551, Reports and Financial Security

Subdivision (a) of Section 551.1 is amended to read:

(a) Each person who is a principal or acts as an agent for another in any of the following activities

within the State must file with the department an organizational report on a form the department prescribes:

(1) solution mining;

(2) drilling, deepening, plugging back or converting oil, gas, [or] solution mining, [and] 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;

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(5) the underground storage in the State of gas;

(6) the practice of well abandonment[s] and salvage of oil and gas subsurface equipment; or

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

Subdivision (b) of Section 551.1 through Section 551.5 are unchanged.


The owner of an oil, [and] gas, [or] solution mining, storage, stratigraphic, geothermal or disposal well

that exceeds or that is expected to exceed 6,000 feet in true measured depth must file financial security for that

well in an amount based upon the anticipated costs of plugging and abandoning that well to the satisfaction of

the department in accordance with Part 555 of this Title[, up to $250,000]. However, the owner is not required

to file financial security under this section exceeding [$2,000,000]an amount specified by the department,

regardless of the number of wells described in this section that the owner may have.


6 NYCRR Part 552, Permits to Drill, Deepen, Plug Back or Convert Wells

Subdivisions (a) and (b) of Section 552.1 are amended and a new subdivision (c) is added to read:

(a) It shall be unlawful for any owner or operator to commence operations to construct the well pad or

access road; drill, deepen, plug back or convert a well for oil and gas exploration, production, input, or storage

purposes to any depth; or drill, deepen, plug back or convert a well for disposal, geothermal, or stratigraphic

purposes to any depth greater than a true vertical depth of 500 feet until [he] the owner or operator has filed an

application with the department and has received a permit as specified below. [This] Except for the drilling of a

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new horizontal well exclusively within the producing horizon of a pool, this application shall not be required for

deepening or plug back operations to be conducted exclusively within the producing horizon of a pool.

(b) Each copy of the application must be accompanied by a neat, legible plat which has been certified as

to correctness by a New York State licensed land surveyor or New York State licensed [civil]professional

engineer. The plat must be drawn to scale and show the boundaries of the lease or unit containing the well, the

distance in feet from the surface location of the well to the two nearest lease or unit boundaries, the distance in

feet from the surface location of the well to the nearest plugged and abandoned well completed in the objective

pool (if same is within one mile) and the distance in feet from the surface location of the well to the nearest

producing well and nearest non-producing unplugged well (if same are within one mile) completed in the

objective pool. Identification of such wells on the plat must include the department-assigned API number and a

notation of the well’s status. Both of the latter two distances may be obtained by scaling from a map, stadia

measurements, pacing, odometer or other reasonably accurate means. However, if the distance between the well

and the nearest well completed in the objective pool is such that there is a possibility of violation of the spacing

requirements of sections 553.1 or 553.3 of this Title, the distance between the surface location of the well and

the nearest well completed in the objective pool shall be measured accurately on the ground. The plat also must

have indicated thereon the decimal latitude and decimal longitude of the well[and the scaled distances in feet in

east-west and north-south directions from the nearest corner of the United States Geological Survey

topographical map upon which the well location is situated, with the topographical map being identified by title,

date and as to whether seven and one-half minute or 15 minute coverage] in North American Datum 83.

(c) Any owner or operator who intends to drill, deepen, plug back, or convert a well where high-volume

hydraulic fracturing is planned must also comply with the application requirements of section 560.3 of this

Title.

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Subdivisions (a), (c) and (d) of Section 552.2 are amended, subdivision (e) is re-lettered subdivision (f), and

new subdivision (e) is added to read:

(a) Upon determination that the application is in order and that the appropriate plugging bond is in force

or proof of financial responsibility has been established as provided in section 551.3 of this Title, the

department shall issue as expeditiously as possible a permit to drill, deepen, plug back or convert a well to the

owner or operator[ utilizing form OG9].

(c) If the operations for which the permit is granted have not commenced and been pursued in a diligent

manner within [180 days] two calendar years from the date of issuance of the permit, said permit shall expire.

(d) If prior to the commencement of operations, a request to modify the spacing unit [are applied for or

are] is pending, the department may suspend the permit. After a decision relative to the spacing [units]unit, the

suspended permit either will be cancelled by the department and the fee refunded, or will be reinstated with the

time while in suspension not charged against the [180-day] two calendar year permit [period] term.

(e) Prior to the commencement of operations, the department may, on its own initiative or at the request

of the owner or operator upon good cause shown, suspend the term of a permit. If said permit is reinstated by

the department, the time during which the permit was suspended will not be charged against the two calendar

year permit term.

Newly re-lettered subdivision (f) of Section 552.2 is amended to read:

(f) Under unusual or emergency circumstances, or for other good cause shown, the department may

permit the commencement of operations by verbal authority of the director or director's deputy prior to the

issuance of a formal permit if a complete application is on file with the department.

A new subdivision (g) is added to Section 552.2 to read:

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(g) Notwithstanding subdivision (c) of this section, when an owner or operator commences operations

pursuant to a permit issued pursuant to this Part, the conditions specified under said permit shall continue in full

force and effect until the well is plugged and abandoned consistent with Part 555 of this Title and the

department has approved final reclamation.


(a) A permit shall not be transferable but may be reissued [as a new permit for any other location] to a

new owner or operator for the same location if prior to the commencement of operations the owner or operator

to whom the permit originally was issued submits[, all in triplicate,] a letter [advising of the location change,

another application completely filled out, and the appropriate plat showing the new location] requesting

reissuance of the permit which identifies the name and address of the new owner or operator and an application

to reissue on a form prescribed by the department. Said application shall be signed by the original owner or

operator and the new owner or operator. Reissuance of the permit, without additional fee, shall be made by the

department after determination that the new owner or operator has filed an organizational report with the

department; the application is in order; and [that]the appropriate plugging bond is in force or proof of financial

responsibility has been established as provided in section 551.3 of this Title. Upon reissuance of the permit by

the department, the original permit shall be deemed cancelled.


6 NYCRR Part 553, Well Spacing

(Statutory authority: Conservation Law, §§ 70, 73, 75, 77, Environmental Conservation Law §§ 23-0501, 23-

0503)

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Subdivisions (a) through (c) of Section 553.1 are re-lettered subdivision (d) through (f), and new subdivisions

(a) through (c) are added to read:

(a) ‘Statewide spacing’ means spacing units for gas or oil wells that are within ten percent of the

following sizes, as applicable, unless another percentage is specifically stated:

(1) For Medina gas pools at any depth, 40 acres with the wellbore within the target formation no

less than 460 feet from any unit boundary, plus, if applicable, the number of additional acres necessary and

sufficient to ensure that any horizontal wellbore within the target formation is not less than 460 feet from any

unit boundary;

(2) For Onondaga reef or Oriskany gas pools at any depth, 160 acres with the wellbore within

the target formation no less than 660 feet from any unit boundary, plus, if applicable, the number of additional

acres necessary and sufficient to ensure that any horizontal wellbore within the target formation is not less than

660 feet from any unit boundary;

(3) For fault-bounded Trenton and/or Black River hydrothermal dolomite gas pools where the

majority of the pool is between 4,000 and 8,000 feet deep, 320 acres with the proposed productive section of the

wellbore within the target formation no less than one-half mile from any other well in another unit in the same

pool and no less than 1,000 feet from any unit boundary that is not defined by a field-bounding fault but in no

event less than 660 feet from any unit boundary;

(4) For fault-bounded Trenton and/or Black River hydrothermal dolomite gas pools where the

majority of the pool is below 8,000 feet, within five percent of 640 acres with the proposed productive section

of the wellbore within the target formation no less than one mile from any other well in another unit in the same

pool and no less than 1,500 feet from any unit boundary that is not defined by a field-bounding fault but in no

event less than 660 feet from any unit boundary;

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(5) For shale gas pools at any depth, for a vertical well outside any existing spacing unit for the

same formation, 40 acres with the wellbore within the target formation no less than 460 feet from any unit

boundary;

(6) For shale gas pools at any depth, for a horizontal well outside any existing spacing unit for

the same formation and with a written commitment from the well operator to drill infill wells pursuant to

subdivision (c) of this section, notwithstanding the ten percent tolerance , up to 640 acres with the initial

horizontal wellbore or wellbores within the target formation approximately centered in the spacing unit and no

wellbore in the target formation less than 330 feet from any unit boundary;

(7) For shale gas pools at any depth, for a horizontal well outside any existing spacing unit for

the same formation and in the absence of a written commitment from the well operator to drill infill wells

pursuant to subdivision (c) of this section, 40 acres with the wellbore within the target formation no less than

330 feet from any unit boundary plus the number of additional acres necessary and sufficient to ensure that the

wellbore within the target formation is not less than 330 feet from any unit boundary;

(8) For all other gas pools where the majority of the pool is above the depth of 4,000 feet, 80

acres with the wellbore within the target formation no less than 460 feet from any unit boundary, plus, if

applicable, the number of additional acres necessary and sufficient to ensure that any horizontal wellbore within

the target formation is not less than 460 feet from any unit boundary;

(9) For all other gas pools where the majority of the pool is 4,000 to 6,000 feet deep, 160 acres

with the wellbore within the target formation no less than 660 feet from any unit boundary, plus, if applicable,

the number of additional acres necessary and sufficient to ensure that any horizontal wellbore within the target

formation is not less than 660 feet from any unit boundary;

(10) For all other gas pools where the majority of the pool is 6,000 to 8,000 feet deep, 320 acres

with the wellbore within the target formation no less than 1,000 feet from any unit boundary, plus, if applicable,

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the number of additional acres necessary and sufficient to ensure that any horizontal wellbore within the target

formation is not less than 1,000 feet from any unit boundary;

(11) For all other gas pools where the majority of the pool is below 8,000 feet, within five

percent of 640 acres with the wellbore within the target formation no less than 1,500 feet from any unit

boundary, plus, if applicable, the number of additional acres necessary and sufficient to ensure that any

horizontal wellbore within the target formation is not less than 1,500 feet from any unit boundary;

(12) For oil pools in the Bass Island, Trenton, Black River, Onondaga reef or other oil-bearing

reefs at any depth, 40 acres with the wellbore within the target formation no less than 460 feet from any unit

boundary, plus, if applicable, the number of additional acres necessary and sufficient to ensure that any

horizontal wellbore within the target formation is not less than 460 feet from any unit boundary; and

(13) For all other oil pools at any depth, the wellbore within the target formation shall be no less

than 165 feet from any lease boundary.

(b) Wells completed under a well permit issued pursuant to paragraph (12) or (13) of subdivision (a) of

this section that do not produce oil may not commence production of natural gas prior to modification of the

spacing unit pursuant to section 553.3 of this Part.

(c) The department may issue permits to drill infill wells on a reasonably uniform pattern within the

spacing unit after an integration order has been issued, if required, and only if it determines that drilling infill

wells is necessary to satisfy the policy objectives of Part 550 of this Title. The distances from the unit

boundaries set forth in this section shall apply to any infill wells. For purposes of this section, new lateral

wellbores drilled from the original wellbore in the unit are not considered infill wells if they are drilled prior to

the first product sales from the original surface location. In a spacing unit established pursuant to paragraph (6)

of subdivision (a) of this section, infill wells shall be deemed necessary.

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Newly re-lettered subdivisions (d) and (e) are amended to read:

(d) Except as provided in subdivisions [(b) and (c)](a) and (e) of this section and absent a department

order establishing spacing units, a well drilled, deepened, plugged back, or converted for the production of oil

and gas cannot be located less than 660 feet from any boundary line of the lease, integrated leases or unit and

cannot be closer than 1,320 feet from any other oil and gas well in the same pool.

(e) Absent a department order establishing spacing units, a well which is on a lease, integrated leases, or

unit having as one of its boundary lines the New York[]-Pennsylvania border may not be drilled, deepened,

plugged back, or converted for the production of oil and gas within 330 feet of that border.


(g) Gas wells drilled, deepened, plugged back or converted in natural gas fields or pools, which were

discovered, developed and operated prior to January 1, 1995 and which are not being extended, are not subject

to the provisions of subdivision (a) of this section.


Subdivisions (d) and (e) of Section 553.3 are repealed, subdivisions (a) though (c) are re-lettered subdivisions

(c) through (e), and new subdivisions (a) and (b) are added to read:

(a) The department shall issue a permit to drill, deepen, plug back or convert a well, if all applicable

requirements are met and the proposed spacing unit conforms to statewide spacing provided in section 553.1 of

this Part.

(b) For wells which meet statewide spacing requirements, issuance of a permit to drill, deepen, plug

back or convert a well shall establish the spacing unit for the permitted well.

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Newly re-lettered subdivisions (c) through (e) of Section 553.3 are amended to read:

(c) [To]For wells exempt from statewide spacing requirements or wells that do not meet such

requirements as provided in section 553.1 of this Part, an order establishing well spacing may be issued by the

department to promote effective development, use or conservation of the natural resources of oil and gas[, an

order establishing well spacing may be promulgated by the department].

(d) Prior to [promulgation] issuance of any spacing order, a public hearing on the matter will be

conducted by the department acting either on its own [motion] initiative or upon receipt of an application

therefor from any interested owner or operator.

(e) Any application for a spacing order shall be made in writing and should include any information the

applying owner or operator deems relevant to the following factors which the department will consider in

deciding upon a spacing order:

(1) the lease and unit boundaries of the lands underlaid by the pool;

(2) the plan of well spacing currently being employed and that proposed for the pool;

(3) the depth at which production from said pool has been found;

(4) the nature and character of the stratum containing the pool and the fluids contained therein;

(5) an estimate of the maximum area which may be drained efficiently and economically by one

well; and

(6) any other available information pertaining to said pool which may be of probative value

to the department in determining the proper spacing therefor, with due and relative allowance for protection of

correlative rights and prevention of waste.

A new subdivision (f) is added to Section 553.3 to read:

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(f) The Department may, upon its own initiative or at the request of the owner or operator, upon good cause

shown, modify an order establishing a spacing unit or a spacing unit which conforms to statewide spacing

without conducting a hearing if a finding has been made that no facts are in dispute after all affected persons

have been provided a reasonable opportunity to comment. For spacing units established pursuant to paragraph

(6) of subdivision (a) of section 553.1 of this Part, failure to drill infill wells pursuant to subdivision (c) of

section 553.1 of this Part shall constitute good cause for the department to initiate a modification of the spacing

unit.


553.4 [Exceptions]Variances

[Where in its opinion there exists good and sufficient reason to permit an exception to the well spacing

provision of sections 553.1, 553.2 and 553.3 of this Part, the] (a) The department may permit reasonable well

location [exceptions which will] variances to the well spacing provisions of subdivisions (d) and (e) of section

553.1 and sections 553.2 and 553.3 of this Part, in order to protect correlative rights and prevent waste. Any

application for such [an exception]a variance shall be made [in writing in triplicate] on a form prescribed by the

department, as a separate attachment to the application for permit as outlined in section 552.1 of this Title and

shall set forth in ample detail the reason or reasons for such [exception] variance request. Upon receipt of this

[exception]variance request, the department shall [promptly schedule a public hearing to facilitate a decision on

the application] publish a notice of intent to issue a permit and spacing variance in the environmental notice

bulletin and provide for a public comment period of at least 15 days. The owner or operator shall also, in

advance of the 15-day public comment period required by this subdivision, provide notice by publication of the

request for a variance, in a manner prescribed by the department. When a location [exception] variance is

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granted, the department may adjust the production from such well or take such other action as it may deem

necessary for the protection of correlative rights or to prevent waste.

(b) Following the public comment period required by subdivision (a) of this section, the department

shall determine whether substantive and significant issues have been raised. If the department receives no

comments or if the comments do not raise a substantive and significant issue, the department may issue the

variance. If the department determines that substantive and significant issues have been raised in a timely

manner, the department shall schedule a hearing to facilitate a decision on the variance application.

Part 554, Drilling Practices and Reports

Subdivisions (a) and (b) of Section 554.1 are unchanged.

Paragraph (1) of subdivision (c) of Section 554.1 is amended and a new paragraph (4) is added to read:

(1) Prior to the issuance of a [well-drilling] permit [for any operation in which the probability exists

that brine, salt water or other polluting fluids will be produced or obtained during drilling operations in

sufficient quantities to be deleterious to the surrounding environment,]to drill, deepen, plug back or convert a

well, or for any operation reported to the department on the Sundry Well Notice and Report form that requires

pre-approval from the department the owner or operator must submit and receive approval for a plan for the

environmentally safe and proper ultimate disposition and/or disposal of [such] used drilling mud, flowback

water and production brine. [For purposes of this subdivision, drilling muds are not considered to be polluting

fluids.] The owner or operator must state in its plan that it will maximize the reuse and/or recycling of used

drilling mud, flowback water and production brine to the maximum extent feasible. Before [requesting]

approving a plan for disposition and/or disposal of such fluids, the department will take into consideration the

known geology of the area, the sensitivity of the surrounding environment to [the polluting] such fluids, and the

history of any other drilling operations in the area. Depending on the method or methods of disposal chosen by

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the [applicant] owner or operator, a permit for discharge and/or disposal may be required by the department in

addition to the [well-drilling] permit to drill, deepen, plug back or convert a well. An [applicant]owner or

operator may also be required at the department’s discretion to submit an acceptable contingency plan, the use

of which shall be required if the primary plan is unsafe or impracticable at the time of disposition or disposal.

(4) [Prior]If applicable, prior to the issuance of a permit to drill, deepen, plug back or convert a

well or for any operation noticed to the department on the Sundry Well Notice and Report form that requires

pre-approval from the department, the owner or operator must submit and receive approval of a plan for the

environmentally safe and proper disposal or beneficial re-use of drill cuttings on-site or off-site.

Paragraphs (2) and (3) of subdivision (c) and subdivisions (d) through (f) of Section 554.1 are unchanged.


The regional headquarters administering to the county in which the well is located shall be notified [in writing

or by telegram] at [or]least 24 hours prior to [the start of actual drilling operations]well spud.



(a) [The]Except for wells intentionally drilled directionally, including those drilled horizontally, the

maximum point at which a well penetrates a producing formation shall not vary unreasonably from the vertical

drawn from the center of the hole at the surface. Minor deviations will be permitted, however, without special

permission for short distances, to straighten the hole, to sidetrack junk, or to correct other mechanical

difficulties. For wells intentionally drilled directionally, including those drilled horizontally, the well path from

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the top of the target interval to the bottom of the target interval and the bottomhole location itself shall not vary

unreasonably from the well path and locations specified on the application to drill, deepen, plug back or convert

a well, unless the owner or operator requests such variation on the department’s Sundry Well Notice and Report

form, and department approval is granted to modify the well’s path and/or locations including bottomhole

location.

Subdivisions (b) and (c) of Section 554.5 are unchanged.

Subdivisions (d) and (e) of Section 554.5 are amended to read:

(d) Controlled directional drilling, [also] including horizontal drilling, shall be permitted upon the

approval of the department. Any owner or operator desiring to intentionally deviate a well from the vertical

shall [first make written application to] notify the department of such proposed deviation on the application to

drill, deepen, plug back or convert a well. The [application, which shall be in addition to the permit application

as provided in section 552.1 of this Title,]notice must [contain]include the following information:

(1) names of the county, field or area, pool and lease and well number; and

(2) description of the surface location and of the target bottomhole location in feet from the two

nearest lease boundaries[;

(3) reason for the proposed intentional deviation;

(4) names and addresses of the offsetting owner or operators and a statement that each has been

sent a copy of the application by registered mail, and the date of such mailing].

(e) The [application] notice must be accompanied by a neat, legible [plat] plan view drawn to scale

which [shows the well, all offsetting leases and the wells located thereon, the pool in which they are completed,

and the names of the offsetting operators] identifies the surface location, top of target interval, bottom of target

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interval and bottomhole location and the vertical section of the wellbore drawn to scale which shows the kickoff

point, top of target interval, bottom of target interval and bottomhole location.

Subdivisions (f) and (g) of Section 554.5 are repealed and subdivision (h) is re-lettered subdivision (f).

Newly re-lettered subdivision (f) is amended to read:

(f) Within 30 days after the completion of an intentionally deviated well, or sooner at the request of the

department for good cause, a complete angular deviation and directional survey of the well obtained by an

approved well surveying company and certified as to correctness shall be filed [with]in a manner prescribed by

the department.


Subdivisions (a) through (e) of Section 554.7 are amended and a new subdivision (f) is added to read:

(a) Within 30 days after the completion of any well, a [completion report] Well Drilling and

Completion Report utilizing a form [OG10]fprescribed by the department shall be filed [in triplicate] by the

owner or operator with the department summarizing thereon the completion details. An interim completion

report shall be filed upon request of the department at any time and within ninety days of any discontinuance in

operations on a well lasting longer than thirty days, with the ninety day timeframe measured from the first day

following discontinuance in operations.

(b) [Each copy of the completion report on form OG10]The Well Drilling and Completion Report also

shall be accompanied by a well log and such other information as the department may specifically require. The

measurement datum for the well log and all other measurements in connection with the well shall be clearly

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specified. The well log also must show the elevation in feet of the measurement datum with respect to mean sea

level.

(c) In the event a multiple completion has been effected in a well, [each copy of] the [completion report

on form OG10]Well Drilling and Completion Report also shall be accompanied by a diagrammatic sketch of the

multiple completion installation and a written resume of the procedures and equipment employed in effecting

the completion and testing to insure separation of the pools.

(d) The owner or operator also may be required to provide up to two sets of bagged and labeled drill

cutting samples upon request of the department. If these are to be required, the owner or operator will be so

advised at the time the permit [on form OG9] to drill, deepen, plugback or convert a well is issued. The samples

are to be washed unless the well is drilled with rotary tools using air or gas as [to] the drilling fluid.

(e) If so requested by the owner or operator, the information contained in the [completion report and]

Well Drilling and Completion Report, a follow-up report to a Sundry Well Notice and Report form, a well log,

and [the] drill cutting samples shall be only for the confidential use of the department and the Geological

Survey of the State Museum and Science Service of the New York State Department of Education until [one

year]six months after the date of commencement of operations for the well so involved. Upon receipt of

successive petitions from the owner or operator, [and the demonstration of continued sufficient good cause,] the

confidential period may be extended for one or more additional periods [of one year in length] up to a

maximum total confidential period of [five] two years.

(f) Within 30 days after completing noticed or approved work under a Sundry Well Notice and Report

form, a Well Drilling and Completion Report or a follow-up report to a Sundry Well Notice and Report form, as

specified by the department, shall be filed by the owner or operator with the department summarizing the details

of such work.

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Part 555, Plugging and Abandonment



(a) It shall be unlawful for the owner or operator [thereof ]to shut in a well [capable of being produced

on a commercial basis] for more than one year without specific permission from the department for an

extension of the time period during which shut-in is permitted.


The opening paragraph and paragraphs (1) through (5) of subdivision (a) of Section 555.5 are amended to read:

(a) The plugging of a well shall be conducted in accordance with the following sequence of operations.

The department at its discretion, may require the tagging of all plugs and require casing and/or cement

evaluation logs to be run to determine proper plugging procedures. The following are minimum requirements

for plugging and the department may impose additional requirements:

(1) The well bore, whether to remain cased or uncased, shall be filled with cement from total

depth to at least [15]50 feet above the top of the shallowest formation from which the production of oil or gas

has ever been obtained in the vicinity. Alternatively, a bridge topped with at least [15]50 feet of cement shall be

placed immediately above each formation from which the production of oil or gas has ever been obtained in the

vicinity.

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(2) [If]For any casing [is to be ]left in the ground, a cement plug of at least [15]100 feet in

length shall be placed [at the bottom of such section of casing] 50 feet below and 50 feet above the casing shoe.

Uncemented casing must be cut and pulled as deep as practicable with a plug approximately 50 feet in length

placed in and above the stub of the casing. If the uncemented casing is unable to be pulled the casing must be

perforated 50 feet below the shoe of the next outer casing and a 100-foot plug placed across that shoe. A

[similar]50 foot plug shall be placed at [the top of such section of casing unless it shall extend to]the surface.

[In the latter event, the casing shall be capped in any such manner as will prevent the migration of fluids and not

interfere with normal soil cultivation.]

(3) If casing extending below the deepest potable fresh water level shall not remain in the

ground, a cement plug of at least [15]50 feet in length shall be placed in the open hole at a position

approximately 50 feet below the deepest potable fresh water level.

(4) If the conductor casing or surface casing is drawn, a cement plug of at least [15]50 feet in

length shall be placed so that the top of the plug is immediately below the point where the lower end of the

conductor or surface casing shall previously have rested (i.e., the casing seat). The hole thereabove shall be

filled with cement, sand or rock sediment or other suitable material in such a manner as will prevent erosion of

the well bore area and not interfere with normal soil cultivation.

(5) [The] Unless otherwise specified in this Part, the interval between all plugs mentioned in

paragraphs (1) through (4) of this subdivision shall be filled with [a heavy mud-laden] gelled fluid with a

minimum density equal to 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.

Paragraph (6) of subdivision (a) and subdivision (b) of Section 555.5 are unchanged.

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Subdivision (c) of Section 555.5 is amended to read:

(c) As a part of the plugging and abandonment operation, the owner or operator shall fill with earth any

pit or other excavation[,including]and fill below plow depth with cement or other grouting material approved by

the department any rat hole or mouse hole, which has been created to facilitate the drilling or production of the

well. In addition, the owner or operator shall make a reasonable effort to smooth the surface adjacent to the

well and filled pit or excavation so as to place the surface in a condition similar to the adjacent terrain and

without undue elevation[ shall be made]. If it can be demonstrated to the satisfaction of the department that no

hazard will result and the landowner has signed an appropriate release, these surface restoration requirements

will be waived.

Subdivision (d) of Section 555.5 and Section 555.6 are unchanged.

Part 556, Operating Practices


Subdivisions (a) and (b) of Section 556.2 are amended to read:

(a) The operating practice requirements of subdivisions (b) through [(d)] (g) of this section shall be

applicable only to gas wells.

(b) No gas from any gas well, except such as is produced in a clean-up period not to exceed 48 hours

after any completion or stimulation operation or workover, plus that used for the controlled testing of the well’s

potential in a period not to exceed 24 hours, plus that used in any operational requirements, shall be permitted to

escape into the air. [Extensions of these time periods shall be granted administratively by the department upon

application therefor by the owner or operator and the demonstration of sufficient good cause.]

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Subdivisions (c) through (e) of Section 556.2 are re-lettered subdivisions (d) through (f) and a new subdivision

(c) is added to read:

(c) The release or flaring of gas, to the extent permitted by subdivision (b) of this section, shall be

performed in accordance with a flare approval issued by the department. Application to the department for a

flare approval, extension of an approved flaring period or for an extension of the time periods specified in

subdivision (b) of this section shall be made on the Sundry Well Notice and Report form.


(g) Sundry Notice and Report on Wells.

(1) The Sundry Well Notice and Report form shall be used by the owner or operator to notify

the department of any permanent change in well bore configuration which does not otherwise require a permit

pursuant to Part 552 of this Title. Such notifications do not require department approval. However, notice to

the department shall be submitted at least 5 days prior to commencing operations unless otherwise specified.

(2) The Sundry Well Notice and Report form shall be used by the owner or operator to notify

the department of operations specified by Parts 550 through 560 of this Title and on the Sundry Well Notice and

Report form, such as well repairs and pressure tests, which do not otherwise require a permit pursuant to Part

552 of this Title. Such notifications do not require department approval. However, notice to the department

shall be submitted at least 5 days prior to commencing operations unless otherwise specified.

(3) A request from the owner or operator for approval to modify previously approved plans,

including a request to modify a well’s path and/or bottomhole location, provided the requested modification

does not have well spacing, compulsory integration or well setback implications, shall be submitted to the

department on the Sundry Well Notice and Report form, and approval of the department must be obtained

before the requested modification is commenced.

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(4) Except for the drilling of a new horizontal well exclusively within the producing horizon of a

pool, a request from the owner or operator for approval to perform deepening or plug back operations to be

conducted exclusively within the producing horizon of a pool shall be submitted to the department on the

Sundry Well Notice and Report form, and approval of the department must be obtained prior to commencing

operations.

(5) A request from the owner or operator for approval to flare during a well completion or re-

completion, including well clean-up, stimulation or testing, shall be submitted to the department on the Sundry

Well Notice and Report form, and approval of the department must be obtained prior to commencing flaring.

Further, a request from the owner or operator for approval to extend an approved flaring period or for an

extension of the time periods specified in subdivision (b) of this section shall be submitted on the Sundry Well

Notice and Report form, and approval of the department must be obtained prior to commencing operations.

(6) A request from the owner or operator for approval to fracture or re-fracture a well after

initial completion or perform a subsequent re-fracturing operation shall be submitted to the department on the

Sundry Well Notice and Report form, and approval from the department must be obtained prior to commencing

operations. A request shall be submitted at least 15 days before operations are requested to begin. Such

operations are subject to the department’s approval after:

(i) review of the planned fracturing or re-fracturing procedures and products, water

source, proposed site disturbance and layout, and fluid disposal plan;

(ii) site inspection by department staff; and

(iii) determination of whether any other department permits are required.

(7) Under unusual or emergency circumstances, or for other good cause shown, the department

may permit the commencement of operations by verbal authority of the director or director’s deputy prior to the

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issuance of a formal approval if a complete Sundry Well Notice and Report form request is on file with the

department.

(8) The department may, for good cause, suspend or terminate any approval to a Sundry Notice

and Report form request granted under this section.


A new Part 560 is adopted to read:

PART 560, OPERATIONS ASSOCIATED WITH HIGH-VOLUME HYDRAULIC FRACTURING

(Statutory Authority: Environmental Conservation Law, §§ 3-0301, 23-0305)

Sec.

560.1 Applicability

560.2 Definitions

560.3 Application Requirements, Procedures and Fees

560.4 Setbacks

560.5 Testing, Recordkeeping and Reporting Requirements

560.6 Well Construction and Operation

560.7 Waste Management and Reclamation

560.1 Applicability

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(a) This Part applies to all vertical and directionally drilled wells, including horizontal wells, where

high-volume hydraulic fracturing is proposed.

(b) This Part supersedes any conflicting provision in Parts 550 through 558 of this Title and each person

who intends to drill, drills, or operates a well subject to this Part shall comply with this Part’s requirements and

with all requirements contained in Parts 550 through 558, inclusive, of this Title that have not been specifically

superseded by provisions of this Part.

560.2 Definitions

(a) For the purpose of this Part, the general definitions in section 550.3 of this Title apply to the extent

not superseded by this Part.

(b) For the purpose of this Part, the following definitions also apply:

(1) ‘access road entrance’ shall mean the midpoint of the line defined by the intersection of the

well site access road and the edge of the traveled part of any State, county, township, or municipal road or any

public street, road or highway.

(2) ‘additive’ shall mean a substance composed of one or more chemical constituents that is

intentionally added to a base fluid.

(3) 'base fluid’ shall mean a substance, such as water or recycled flowback water, into which

additives are mixed to form the hydraulic fracturing fluid which transports proppant, if used.

(4) ‘best management practices’ shall mean measures or methods used to prevent or minimize

potential impacts on air quality, biological resources, land, and water quality caused by drilling, deepening,

plugging back and converting or producing a well subject to this Part.

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(5) ‘CAS Number’ shall mean the unique identification number assigned to a chemical by the

Chemical Abstracts Service, which is the division of the American Chemical Society that is the globally

recognized authority for information on chemical substances.

(6) ‘chemical constituent’ shall mean any element, compound or mixture with its own specific

name or identity, such as a CAS Number.

(7) ‘chemical disclosure registry’ shall mean the chemical registry website known as

FracFocus.org developed by the Groundwater Protection Council and the Interstate Oil and Gas Compact

Commission. If such website becomes permanently inoperable, then chemical disclosure registry shall mean

another publically accessible information website that is designated by the Department.

(8) ‘chemical family’ shall mean a group of chemicals that share similar chemical properties and

have a common general name.

(9) ‘complete application’ under this Part shall have the same meaning as it does under section

621.2 of this Title.

(10) ‘completion’ shall mean the preparation of a well for production after it has been drilled to

the objective formation.

(11) ‘final reclamation’ shall mean the reclamation of a well site following the end of

production. This includes the regrading of lands, alleviating compaction, replacement of top soil, and

revegetation, to restore and stabilize the site.

(12) ‘flowback’ shall mean phase or period during initial completion and clean-up of the well or

clean-up of a well following a re-fracture or workover.

(13) ‘flowback water’ shall mean liquids and solids produced following drilling and initial

completion and clean-up of the well or clean-up of a well following a re-fracture or workover.

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(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 account the sum of all water-

based fluids, including fresh water and recycled flowback water, used in all high-volume hydraulic fracturing

stages.

(15) ‘intermittent stream’ shall mean a stream channel that contains flowing water for only a

portion of the year.

(16) ‘material safety data sheet, or MSDS’ shall mean written or printed material concerning a

hazardous chemical that is prepared in accordance with 29 CFR 1910.1200(g).

(17) ‘objective formation’ shall mean the reservoir or geologic target specified on an application

for a permit to drill, deepen, plug back or convert a well.

(18) ‘partial reclamation’ means the reclamation of a well site following completion of a well,

and in the case of a multi-well pad, completion of the last well on the multi-well pad. This includes the

reclamation of pits, regrading of lands and the revegetation of lands outside the well pad.

(19) ‘perennial stream’ shall mean a stream channel that has continuous flow in parts of its bed

all year round during years of normal rainfall.

(20) ‘primary aquifer’ shall mean a highly productive aquifer presently being utilized as a

source of water supply by a major municipal supply system.

(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.

(22) ‘product’ shall mean an additive that is manufactured using precise amounts of specific

chemical constituents and is assigned a commercial name under which the substance is sold or utilized.

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(23) ‘production brine’ shall mean formation water co-produced from an oil or gas well after the

well is connected to a gathering line or stock tank.

(24) ‘proppant’ shall mean sand or any natural or man-made material that is carried in

suspension by the hydraulic fracturing fluid and serves to keep the induced fractures open when hydraulic

fracturing fluid is withdrawn after a hydraulic fracturing treatment.

(25) ‘public water supply’ shall mean either a community or non-community system which

provides piped water to the public for human consumption if the system has a minimum of five (5) service

connections, or regularly serves a minimum average of 25 individuals per day at least 60 days per year.

(26) ‘reservoir’ shall mean a ponded or impounded surface waterbody designated for use as a

public water supply, any part of which is classified as A or AA in its entirety pursuant to Parts 800 to 941 of this

Title.

(27) ‘safety data sheet, or SDS’ shall mean written or printed material concerning a hazardous

chemical that is prepared in accordance with 29 CFR 1910.1200(g).

(28) ‘stage’ shall mean the isolation and/or stimulation of a specific interval of the objective

formation.

(29) ‘stage plug’ shall mean a device used to mechanically isolate a specific interval of the

objective formation for the purpose of well stimulation.

(30) ‘well pad’ shall mean the area directly disturbed during drilling and operation of a gas well.

(31) ‘well site’ shall mean the well pad and access roads, equipment storage and staging areas,

vehicle turnarounds, and any other areas directly impacted by activities involving a well subject to this Part.

(32) ‘wetland’ shall mean any area regulated pursuant to Article 24 of the Environmental

Conservation Law and any other wetland regulated under Section 404 of 33 U.S.C. 1251, et seq.

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560.3 Application Requirements, Procedures and Fees

(a) Application requirements. In addition to the requirements found in Part 552 of this Title, an

application for a permit to drill, deepen, plug back or convert a well subject to this Part shall contain

information specified on a department-approved form including:

(1) measured from the ground surface, the minimum depth to the top of the objective formation

for the entire proposed length of the wellbore;

(2) the estimated maximum depth and elevation of bottom of potential fresh water, and the basis

for such estimate (water well information, other well information, previous drilling on the well pad, published

or private reports, or other department-approved source);

(3) the proposed total volume of water-based fluid, including a breakdown of individual

volumes of fresh water and other water-based fluids, to be used in hydraulic fracturing and the basis for the

estimate of proposed total volume of fluid;

(4) the proposed source or sources of fresh water and other water-based fluids and the status of

approvals needed to withdraw any such water;

(5) scaled distance from the proposed surface location of the well and the closest edge of the

proposed well pad to any water supply reservoir, intake, water well or domestic supply spring, or water well or

spring used for water supply for crops or livestock within 2,640 feet, including any public or private wells, and

community or non-community systems;


proposed well pad to any primary or principal aquifer boundary, perennial or intermittent stream, wetland,

storm drain, lake, or pond within 500 feet, and any surface water body within 500 feet that is a tributary to a

public drinking water supply;

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proposed well pad to any inhabited private dwellings or places of assembly within 1,320 feet;

(8) identification of any abandoned wells subject to Parts 550 through 559 of this Title within

the proposed spacing unit and within one mile of the proposed surface location of the well, and information on

such wells, as specified by the department;

(9) a description of the planned construction and capacity of any reserve pit;

(10) where applicable, a description of the closed-loop tank system;

(11) the number and individual and total capacities of receiving tanks for flowback water ;

(12) a description of the drilling and hydraulic fracturing engines to be used, the type of fuel

needed for such engines and a description of any planned air emission control measures;

(13) the status of the availability of a commercial sales line and interconnecting gathering line to

the well or multi-well pad and operating compressor station, if applicable;

(14) the fluid and drill cuttings disposal plans, as required by paragraphs 554.1(c)(1) and

554.1(c)(4) of this Title.

(15) the proposed blowout preventer use and test plan for all drilling and completion operations

specifying:

(i) the pressure rating of any annular preventer, rams (including a description of type and

number of rams), choke manifold and connecting line from the blowout preventer to the choke

manifold;

(ii) timing, duration, pressure and frequency of testing and/or visual inspection of the

blowout preventer and related equipment including any scheduled retesting of equipment;

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(iii) test pressure(s) and timing for any internal pressure testing of surface, intermediate

and production casing strings, and duration of tests including an explanation as to how the test pressure was

determined;

(iv) test pressure(s) and anticipated depth(s) of any surface and/or intermediate casing

seat integrity tests. If a casing seat integrity test will not be conducted on a casing string with a blowout

preventer installed on it, an explanation must be provided why such a test is not required and how any flow will

be managed;

(v) distance from well to the remote actuator which is powered by a source other than rig

hydraulics;

(vi) a system for recording, documenting and retaining the results of all pressure tests

and inspections conducted during drilling and/or completion operations;

(vii) a copy of the owner’s or operator’s well control barrier policy that identifies

acceptable barriers to be used during identified operations; and

(viii) any other related information or data required by the department that is necessary

to ensure environmental protection and public safety.

(16) a list of invasive species found at the well site and description of the best management

practices which will be used for preventing the spread of these invasive species, including measures being used

to prevent new invasive species from being transported to the site;

(17) a partial site reclamation plan that describes the methods for partially reclaiming the well

site following completion, including a description of best management practices for restoration of native plant

cover;

(18) a transportation plan indicating the planned route for delivery of water to the site for

hydraulic fracturing, the proposed route for transport of flowback water requiring tracking by means of the

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department’s Drilling and Production Waste Tracking Form, all other truck trips associated with hydraulic

fracturing at the site, and an estimated number of truck trips associated with same. Further, the transportation

plan must include a copy of any road use agreement(s) between the owner or operator and any municipalities or

documentation of the owner’s or operator’s efforts to obtain such agreements; and

(19) a Safety Data Sheet or Material Safety Data Sheet, as appropriate, for each additive to be

used in the drilling fluid, if not already on file with the department.

(b) Plat requirements. In addition to the well plat requirements contained in subdivision (b) of section

552.1 of this Title, the plat must have indicated thereon the decimal latitude and decimal longitude of the access

road entrance in North American Datum 83.

(c) Mapping requirements. With each application for a permit to drill, deepen, plug back or convert a

well subject to this Part, the owner or operator shall provide:

(1) a plan view of the wellbore including surface and bottomhole locations and a vertical section

of the wellbore showing the land surface elevation and wellbore elevation with an indication of the surface

location along the path of the proposed wellbore of the minimum true vertical depth measured from the ground

surface to the top of the objective formation.

(2) a topographic map of the area within at least 2,640 feet of the proposed surface location of

the well showing the location and orientation of the proposed well pad and a close-up map of the well pad

showing the placement of fueling tanks, reserve pit and receiving tanks for flowback water, the location of the

access road, type and extent of vegetative cover and the location of any flowback water pipelines or

conveyances.

(3) a map at a scale specified by the department showing the location and identity of all

occurrences of invasive species within the proposed well site,

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(4) a plan view drawing of the well site illustrating where partial reclamation will be

accomplished following completion of all wells on the well pad.

(d) Hydraulic Fracturing Fluid Disclosure.

(1) With each application for a permit to drill, deepen, plug back or convert a well subject to this

Part, the owner or operator, directly or through a service company and/or chemical supplier(s), shall provide the

following information on a department-approved form, except paragraph (vii) which shall be provided as a

separate attachment:

(i) proposed volume of each product to be used in hydraulic fracturing;

(ii) identification of each additive proposed for use, listed by product name and a brief

description of its function,;

(iii) a Safety Data Sheet or Material Safety Data Sheet, as appropriate, for each product

to be used if the current version is not already on file with thedepartment;

(iv) proposed percent by weight of base fluid, each additive and proppants, if used;

(v) identification of all chemical constituents, by chemical names and associated CAS

Numbers, to be intentionally added to the base fluid (which may be submitted in a format that does or does not

correlate the chemical constituents to the respective products);

(vi) the proposed actual or maximum concentration of each chemical constituent

intentionally added to the base fluid, expressed as a percent by mass of the total volume of hydraulic fracturing

fluid to be used;

(vii) identification of the proposed hydraulic fracturing service company; and

(viii) documentation, to the department’s satisfaction, utilizing existing data and studies,

that proposed additives exhibit reduced aquatic toxicity and pose at least as low a potential risk to water

resources and the environment as all known available alternatives; or documentation, to the department’s

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satisfaction, that available alternative products are not effective in achieving the desired results or economically

feasible. The owner or operator must use proposed additives that satisfy the foregoing requirement.

(2) The department will disclose to the public the information submitted pursuant to paragraph

(1) of this subdivision except that owner or operators or other persons who supply information subject to

paragraph (1) of this subdivision may request such records to be exempt from disclosure as trade secret as

provided by Part 616 of this Title. Records determined by the department to be exempt from disclosure shall not

be considered a well record for purposes of disclosure.

(3) To the extent that information considered trade secret has already been submitted to the

department, whether in connection with a prior application for a permit to drill, deepen, plug back or convert, or

otherwise, the prior submission may be referenced in the information submitted pursuant to paragraph (1) of

this subdivision, in lieu of submitting duplicative trade secret information.

(4) Sharing of information among well owners, operators, service companies and chemical

suppliers. Each involved well owner, operator, service company and/or chemical supplier shall supply accurate

information to the entity submitting information pursuant to paragraph (1) of this subdivision to facilitate

compliance with paragraph (1) of this subdivision. Nothing herein shall preclude agreements between or among

the well owner, operator, service company and/or chemical supplier to preserve the confidentiality of

information that is required to be submitted to the department. Nothing herein shall require the well owner,

operator, service company and/or chemical supplier to disclose trade secret information to one another, as such

information can be disclosed directly to the department, on the department-approved form, by any of the

entities.

(e) Application procedures. The review process for applications for a permit to drill, deepen, plug back

or convert that propose well stimulation using high-volume hydraulic fracturing under this Part is as follows:

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(1) An application for a permit under this Part shall be made in a format and on forms prescribed

by the department.

(2) The department shall determine whether the application is functionally complete for purposes

of department review within 10 business days after it is submitted to the department. The department shall

inform the applicant of any deficiencies.

(3) The department shall provide or cause to be provided the applicant’s name, well name and

number, and location coordinates of the well to the supervisor of the town or the mayor of the village or city, as

the case may be, or any other point of contact designated, in a manner prescribed by the department, by the

municipal governing board to the department for receipt of applications under this Part.

(4) Where a well pad is proposed within one mile of the territory of an Indian Nation, the

department shall provide that nation with the applicant’s name, well name and number, and location coordinates

of the well for the purpose of initiating consultation.

(5) There shall be a public notice period on the draft permit of fifteen days from the date that the

notice of availability of the draft permit is published in the Environmental Notice Bulletin. In conjunction with

such notice, the department shall publish or cause to be published a copy of the draft well permit on a publicly

available website. The department will only consider comments on local and site-specific issues that have not

been addressed in the Final Generic Environmental Impact Statement on the Oil, Gas and Solution Mining

Regulatory Program (1992) or in any final supplemental generic environmental impact statement accepted by

the Department pursuant to Article 8 of the Environmental Conservation Law and Part 617 of this Title.

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(6) The department shall mail or electronically provide to the applicant or its designated agent

the decision on an application after the close of the public notice period.

(7) Unless otherwise required by law, applications for the permitting of additional wells on a

well pad associated with any well that has already been granted a permit pursuant to this Part shall not be

subject to the public notice or comment period provided for under this section.

(8) If the application requires preparation of a supplemental environmental impact statement,

timeframes shall be governed by Part 617 of this Title.

(9) If an application under this Part requires more than one permit from the department, the

applicant must simultaneously submit all the necessary applications to the department or demonstrate to the

department’s satisfaction that there is good cause not to do so.

(10) Pursuant to section 621.3(c) of this Title, when an application under this Part also requires

an individual permit that is subject to the Uniform Procedures Act (Article 70 of the Environmental

Conservation Law and its implementing regulations set out in Part 621 of this Title) the department may process

all applications under the procedures of the Uniform Procedures Act.

(f) Application fees. The applicant must pay all permit fees required under the Environmental

Conservation Law. The applicant must also pay any costs assessed by the department pursuant to section 8-

0109(7) of the Environmental Conservation Law and its implementing regulations set out at sections 617.13 and

618.1 of this Title. The department will not be required to issue a decision on an application, nor will a permit

be deemed issued, until the applicant has posted any financial security required and paid all fees or costs

assessed by the department.

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560.4 Setbacks

(a) No well pad or portion of a well pad may be located:

(1) within 500 feet from a residential water well, domestic supply spring or water well or spring

used as a water supply for livestock or crops;

(2) within 500 feet from an inhabited dwelling or place of assembly;

(3) within a primary aquifer and a 500-foot buffer from the boundary of a primary aquifer;

(4) within a 100-year floodplain; and

(5) within 2,000 feet of any public water supply (municipal or otherwise, or the boundaries of

any public water supply reservoir, natural lake or man-made impoundment (except engineered impoundments

constructed for fresh water storage associated with fracturing operations) .

(b) All distances noted above are measured from the closest edge of the well pad.

(c) The department may permit reasonable well location variances to the setback requirements in

sections 560.4(a) (1), 560.4(a) (2) and 750-3.3 (a)(6) of this Title. Any such variance to the setback requirement

of section 560.4(a) (1) or Section 750-3.3(a)(6) of this Title shall be subject to the written consent of the

landowner or landowners whose residential water well, domestic supply spring, or water well or spring used for

livestock or crops is located within 500 feet of the proposed well pad. Any variance to the setback requirement

of section 560.4(a) (2) of this Part shall be subject to the written consent of the landowner of the inhabited

dwelling or place of assembly within 500 feet of a well pad, and, in the case of an inhabited dwelling, the

written consent of all tenant(s), if any. The applicant for a variance must show that there are no reasonable

allowable alternative locations within the spacing unit where the well pad could be sited consistent with the

setback requirements of this section and the well spacing requirements of Part 553 of this Title. In approving a

variance, the department shall maximize the separation distance by granting the minimum variance that it deems

necessary and adequate. The department shall have the authority to impose such reasonable and necessary

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conditions to minimize any adverse impact on the water supplies, inhabited dwellings or places of assembly

within 500 feet of the well pad.

560.5 Testing, Recordkeeping and Reporting Requirements

(a) An emergency response plan containing elements specified by the department must be prepared by

the owner or operator and kept on-site during any well operation from well spud through well completion. The

well’s name and number, its location in decimal latitude and longitude in North American Datum 83, the

location of the access road entrance in decimal latitude and longitude in North American Datum 83 and a list of

emergency contact numbers for the area in which the well site is located must be included in the emergency

response plan, and such information must be prominently displayed on a weatherproof sign at the well site

during operations covered by the department-issued permit to drill, deepen, plug back or convert. A copy of the

emergency response plan must be provided to the department at least three days prior to well spud.

(b) The relevant county emergency management office must be notified by the owner or operator of the

well’s name and number, its API Number, its location in decimal latitude and longitude in North American

Datum 83, and the location of the access road entrance in decimal latitude and decimal longitude in North American

Datum 83, prior to spudding the well, at the first occurrence of flaring while drilling, prior to pumping the first

stage into the well to conduct high-volume hydraulic fracturing, and prior to the first occurrence of flaring for

well clean-up. A record of the type, date and time of any notification provided to the county emergency

management office must be maintained by the owner or operator and made available to the department upon

request for a period up to and including five years after the well is permanently plugged and abandoned

consistent with Part 555 of this Title. For multi-well pads, the five-year term specified in this paragraph shall

begin after the last well subject to Part 552 of this Title is permanently plugged and abandoned pursuant to a

plugging permit issued by the department.

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(c) Any non-routine incident of potential environmental and/or public safety significance during access

road and well pad construction, well drilling and stimulation, well production, and well plugging that may affect

the health, safety, welfare, or property of any person must be verbally reported to the department within two

hours of the incident’s known occurrence or discovery, with a written report detailing the non-routine incident

to follow within twenty-four hours of the incident’s known occurrence or discovery. Non-routine incidents of

potential environmental and/or public safety significance may include, but are not limited to: casing, drill pipe

or hydraulic fracturing equipment failures, cement failures, fishing jobs, fires, seepages, blowouts, surface

chemical spills, observed leaks in surface equipment, observed pit liner failure, surface effects at previously

plugged or other wells, observed effects at water wells or at the surface, complaints of water well

contamination, anomalous pressure and/or flow conditions indicated or occurring during hydraulic fracturing

operations, or other potentially polluting non-routine incident or incident that may affect the health, safety,

welfare, or property of any person. Provided the environment and public safety would not be further

endangered, any action and/or condition known or suspected of causing and/or contributing to a non-routine

incident must cease immediately upon known occurrence or discovery of the incident, and appropriate initial

remedial actions commenced. The required written non-routine incident report noted above must provide details

of the incident and include, as necessary, a proposed remedial plan for department review and approval. In the

case of suspended hydraulic fracturing pumping operations and non-routine incident reporting of such, the

owner or operator must receive department approval prior to recommencing hydraulic fracturing activities in the

same well. The department may issue an order to take appropriate actions consistent with this subdivision,

including an order to cease all activities.

(d) Water well and spring testing:

(1) prior to site disturbance for a new pad or a new well spud for an existing pad, the owner or

operator must make all reasonable attempts, with the landowner’s permission, to sample and test, at the owner’s or

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operator’s expense, all residential water wells, domestic supply springs, and water wells and springs that are used as

water supply for livestock or crops, that are within 1,000 feet of the well pad for the parameters specified by the

department, which at a minimum include barium, chloride, conductivity, gross alpha/beta, iron, manganese,

dissolved methane and ethane, pH, sodium, static water level (when possible), total dissolved solids (TDS), and

volatile organic compounds (VOCs), specifically BTEX. If no wells or springs are available for sampling within

1,000 feet of the well pad, either because there are none of record or because any landowners within 1,000 feet

of the well pad deny the owner or operator permission to sample their wells or springs, then the owner or

operator must make all reasonable attempts, with the landowner’s permission, to sample and test such water wells

and springs within 2,000 feet for the parameters specified by the department. The landowner of any water well

or spring tested must be provided with a copy of the test results within 30 days of the owner’s or operator’s

receipt of the results.

(2) the owner or operator must sample and test residential water wells and springs in the same

manner as provided in paragraph (1) of this subdivision, at other intervals specified by the department after the

well reaches total measured depth specified on an application for a permit to drill. Any and all significant

deviation(s) from the baseline compositions must be reported to the Department within 5 business days of

determining any such deviation.

(3) copies of test results and documentation related to delivery or attempted delivery of test

results to the owners of water wells or springs must be submitted to the New York State Department of Health

within 45 days of the owner or operator’s receipt of the results, and must be made available to the department

upon department request. Such records must be maintained and available to the department for a period up to

and including five years after the well is permanently plugged and abandoned consistent with Part 555 of this

Title. For multi-well pads, the five-year term specified in this paragraph shall begin after the last well subject to

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Part 552 of this Title is permanently plugged and abandoned pursuant to a plugging permit issued by the

department.

(e) The results of blowout preventer testing required by paragraph 560.3(a)(15) of this Part must be

available to the department at the well site during the corresponding operation, and to the department upon

request at any time during the period up to and including five years after the well is permanently plugged and

abandoned consistent with Part 555 of this Title. For multi-well pads, the five-year term specified in this

paragraph shall begin after the last well subject to Part 552 of this Title is permanently plugged and abandoned

pursuant to a plugging permit issued by the department. The record for each pressure test, at a minimum, must

identify the equipment or casing being tested, the date of the test, the minimum and maximum test pressures in

pounds per square inch gage, the test medium (e.g., water, brine, mud, air, nitrogen) and its density, test

duration, and the results of the test including any pressure drop;

(f) A Drilling and Production Waste Tracking Form must be completed and such completed forms shall

be retained for three years by the owner or operator, transporter and destination facility for any used drilling

mud, flowback water, production brine and drill cuttings removed from the well site and must be made

available to the department upon request during this period. For any such waste disposed instead of recycled or

reused, the owner or operator must make the completed Drilling and Production Waste Tracking Form available

to the public on the owner’s or operator’s publically available website within 30 days of receipt of the waste by

the disposal facility. Upon department request, the owner or operator shall be responsible for obtaining and

providing to the department a copy of any completed Drilling and Production Waste Tracking Form with the

signatures of the transporter and destination facility for any such waste removed from a well site covered by a

permit to drill issued to the owner or operator pursuant to Part 552 of this Title.

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(g) If any fluid or other waste material is moved off site by pipeline or other piping, the owner or

operator must maintain a record of the date and time the fluid or other material left the site, the quantity of fluid

or other material, and its intended disposition and use at that destination or receiving facility.

(h) Hydraulic Fracturing Fluid Disclosure Following Well Completion:

(1) Concurrent with the filing of the Well Drilling and Completion Report required under

Section 554.7 of this Title or the follow-up report to a Sundry Well Notice and Report form required under

section 554.6 of this Title, the well owner or operator, directly or through a service company and/or chemical

supplier(s), shall provide the following information to the department on a department-approved form:

(i) owner or operator name;

(ii) well name and number, and API number;

(iii) county in which the well is located;

(iv) the longitude and latitude of the wellhead;

(v) the true vertical depth of the well;

(vi) the date of the hydraulic fracturing treatment;

(vii) the total volume of the water-based fluid used in the hydraulic fracturing treatment

of the well;

(viii) identification of each additive, listed by product name, intentionally added to the

base fluid and a brief description of its function;

(ix) identification of all chemical constituents, by chemical names and associated CAS

Numbers, intentionally added to the base fluid (which may be submitted in a format that does or does not

correlate the chemical constituents to the respective products);

(x) the actual or maximum concentration, in percent by mass, of each chemical

constituent intentionally added to the base fluid.

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(2) The department will disclose to the public the information submitted pursuant to paragraph

(1) of this subdivision except that the owner or operator or other persons who supply information subject to

paragraphs (ix) and/or (x) may request that the information be exempt from disclosure as trade secret as

provided by Part 616 of this Title. Records determined by the department to be exempt from disclosure shall not

be considered a well record for the purposes of disclosure.

(3) To the extent that information asserted by the owner or operator or other persons who supply

information to be trade secret has already been submitted to the department, whether in connection with a prior

application for permit to drill, deepen, plug back or convert, or otherwise, the prior submission may be

referenced in the information submitted pursuant to paragraph (1) of this subdivision, in lieu of submitting

duplicative trade secret information.

(4) Concurrent with the filing of the hydraulic fracturing fluid information pursuant to paragraph

(1) of this subdivision, the well owner or operator, directly or through a service company and/or chemical

supplier(s), shall provide to the chemical disclosure registry, on the chemical disclosure registry form, all of the

information required pursuant to paragraph (1) of this subdivision, with the exception of information asserted by

the owner or operator or other persons who supply information to be trade secret and therefore requested to be

exempt from disclosure pursuant to paragraph (2) of this subdivision. Trade secret information is not required to

be disclosed to the chemical registry disclosure.

(i) If the specific identity of a chemical constituent and/or the concentration of a

chemical constituent are asserted by the owner or operator or other persons who supply information to be trade

secret, the owner or operator or other persons who supply information to the chemical disclosure registry must

indicate this on the chemical disclosure registry form.

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(ii) If the specific identity of a chemical constituent is asserted by the owner or operator

or other persons who supply information to be trade secret, the chemical family or other similar descriptor

associated with the chemical constituent must be provided on the chemical disclosure registry form.

(5) Sharing of information among well owner, operator, service company and/or chemical

suppliers. Each involved well owner, operator, service company and/or chemical supplier shall supply accurate

information to the entity submitting information pursuant to paragraph (1) of this subdivision to facilitate

compliance with paragraph (1) of this subdivision. Nothing herein shall preclude agreements between or among

the well owner, operator, service company and/or chemical supplier to preserve the confidentiality of

information that is required to be submitted to the department. Nothing herein shall require the well owner,

operator, service company and/or chemical supplier to disclose trade secret information to one another, as such

information can be disclosed directly to the department, on the department-approved form, by any of the

entities.

560.6 Well Construction and Operation

(a) Site Preparation

(1) Unless otherwise required by private lease agreement and in consideration of avoiding

bisection of agricultural fields, any new access road must be located as far as practical from water resources,

inhabited private dwellings and places of assembly.

(2) Unless otherwise approved or directed by the department, all topsoil stripped to facilitate the

construction of the well pad and access road(s) must be stockpiled, stabilized and remain on site for use in either

partial or final reclamation.

(3) Piping, conveyances, valves and tanks in contact with flowback water must be constructed of

materials compatible with flowback water.

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(4) Any reserve pit, drilling pit or mud pit on the well pad must be maintained in a leak-free

condition, and such pits which will be used for more than one well must be constructed as follows:

(i) total pit volume may not exceed 250,000 gallons, or 500,000 gallons for multiple pits

on one tract or an adjacent or related tract of land under common ownership or control;

(ii) pit sidewalls and bottoms must be adequately cushioned and free of objects capable

of puncturing or ripping the liner;

(iii) pits constructed in unconsolidated sediments must have beveled walls (45 degrees or

less);

(iv) the pit liner must be sized and placed with sufficient slack to accommodate

stretching;

(v) liner thickness must be at least 30 mils and be compatible with the drilling muds and

well fluids;

(vi) seams must be factory installed or field seamed in accordance with the

manufacturer’s specifications.

(b) Site Maintenance

(1) For any well:

(i) secondary containment is required for all fueling tanks placed on-site;

(ii) fueling tanks must not be placed within 500 feet of a perennial or intermittent stream,

storm drain, regulated wetland, lake or pond;

(iii) fueling tank filling operations must be supervised at the fueling truck and at the tank

if the tank is not visible to the fueling operator from the truck; and

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(iv) troughs, drip pads or drip pans are required beneath the fill port of a fueling tank

during filling operations if the fill port is not within the secondary containment required by subparagraph (i) of

this subdivision.

(2) Except for freshwater storage, fluids must be removed from any on-site pit prior to any 45-

day gap in use and the pit must be inspected by the department prior to resuming use.

(c) Drilling, Hydraulic Fracturing and Flowback

(1) The owner or operator must provide the drilling company with a well prognosis indicating

anticipated formation top depths with appropriate warning comments prior to well spud. The prognosis must be

reviewed by all crew members and posted in a prominent location in the doghouse. The owner or operator must

revise the prognosis and inform the drilling company in a timely manner if drilling reveals significant variation

between the anticipated and actual geology and/or formation pressures.

(2) Individual crew member responsibilities for blowout control must be posted in the doghouse

or other appropriate location and each crew member must be made aware of such responsibilities prior to spud

of any well being drilled or when another rig is moved on a previously spudded well and prior to the

commencement of completion work by any rig, snubbing unit or coiled tubing unit.

(i) During all drilling and completion operations when a blowout preventer is installed,

tested or in use, the owner or operator orits designated representative must be present at the well site and such

person or personnel must have a current well control certification from an accredited training program that is

acceptable to the department. Documentation of such certification must be available at the well site during such

operations and provided to the department upon request.

(ii) Appropriate pressure control procedures and equipment in proper working order

must be properly installed and employed while conducting drilling and completion operations including

tripping, logging, running casing into the well, and drilling out solid-core stage plugs. Unless otherwise

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approved by the department, a snubbing unit or coiled tubing unit with a blowout preventer must be used to

enter any well with pressure or to drill out one or more solid-core stage plugs.

(3) As specified on a permit to drill, deepen, plug back and convert or approval for the Sundry

Well Notice and Report form, the department must be notified prior to testing of the blowout preventer and

related equipment. Pressure testing of the blowout preventer and related equipment for any drilling or

completion operation must be performed in accordance with the approved blowout preventer use and test plan

required by section 560.3 of this Part, and any deviation from the approved plan must be approved by the

department. Testing must be conducted in accordance with industry standards or other procedures approved by

the department. Unless otherwise approved by the department, the blowout preventer use and test plan must

meet the following requirements:

(i) A well control barrier policy shall be developed by the owner or operator that

identifies acceptable barriers to be used during identified operations. Such policy must employ, at a minimum,

two mechanical barriers capable of being tested when conducting any drilling or completion operation below

the surface casing. In no event shall a stripper rubber or a stripper head be considered an acceptable barrier.

(ii) Testing of the blowout preventer shall include testing after the blowout preventer is

installed on the well but prior to drilling below the last cemented casing seat. Pressure control equipment,

including the blowout preventer, that fails any pressure test must not be used until it is repaired and passes the

pressure test.

(iii) A remote blowout preventer actuator, which is powered by a source other than rig

hydraulics, shall be located at least 50 feet from the wellhead. All lines, valves and fittings between the blowout

preventer and the remote actuator and any other actuator must be flame resistant and have an appropriate rated

working pressure.

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(4) In accordance with subdivision (b) of section 554.7 of this Title, all freshwater, brine, oil and

gas shows must be documented on the department’s Well Drilling and Completion Report. This includes all

naturally occurring methane shows in the conductor hole, if drilled, and the surface hole. In the event hydrogen

sulfide is encountered in any portion of the well, all activities must be conducted by the owner or operator in

conformance with industry standards for drilling of wells where hydrogen sulfide is present.

(5) The intentional annular disposal of drill cuttings or fluid is prohibited.

(6) All fluids must be contained on the site until properly removed in compliance with the fluid

disposal plan approved in accordance with section 554.1 of this Title.

(7) A closed-loop tank system must be used instead of a reserve pit to manage drilling fluids and

cuttings for any of the following:

(i) horizontal drilling in the Marcellus Shale unless an acid rock drainage mitigation plan

for on-site burial of such cuttings is approved by the department; and

(ii) any drilling requiring cuttings to be disposed of off-site.

(8) Cuttings may be removed from the site in the primary capture container (e.g., tank or bin) or

transferred on-site via a transfer area to a secondary container or truck (or other transport vehicle) for off-site

disposal or disposition. If a cuttings transfer area is employed, it must be lined with a material acceptable to the

department. Transfer of cuttings to an on-site stock pile is prohibited, regardless of any liner under the stock

pile. Offsite transport of all cuttings must be undertaken by a waste transporter pursuant to a permit issued

pursuant to Part 364 of this Title.

(9) Only biocides registered for use in New York may be used for any operation at the well site.

Products must be properly labeled, and the label must be kept on-site during application and storage.

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(10) With respect to all surface, intermediate and production casing run in the well, and in

addition to the department’s casing and cementing requirements and any approved centralizer plan for

intermediate casing, the following shall apply:

(i) all casings must be new and conform to specifications identified in the permit to drill,

deepen, plug back or convert;

(ii) welded connections are prohibited;

(iii) casing thread compound and its use must conform to specifications identified in the

permit to drill, deepen, plug back or convert;

(iv) in addition to centralizers otherwise required by the department except for

production casing, at least two centralizers, one in the middle and one at the top of the first joint of casing run in

the hole, must be installed and all bow-spring style centralizers used must conform to the specifications

identified in the permit to drill, deepen, plug back or convert;

(v) cement must conform to specifications identified in the permit to drill, deepen, plug

back or convert and the cement slurry must be prepared to minimize its free water content in accordance with

specifications approved by the department, and contain a gas-block additive or, as approved by the department,

be a cement blend that is functionally equivalent;

(vi) prior to cementing any casing string, the borehole must be circulated and

conditioned to ensure an adequate cement bond;

(vii) a spacer of adequate volume, makeup and consistency must be pumped ahead of the

cement;

(viii) the cement must be pumped at a rate and in a flow regime that inhibits channeling

of the cement in the annulus;

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(ix) after the cement is pumped, the owner or operator must wait on cement (WOC) until

the cement achieves a calculated (e.g., performance chart) compressive strength of at least 500 pounds per

square inch gage (psig), and a minimum WOC time of 8 hours before the casing is disturbed in any way,

including installation of a blowout preventer or a rig skid. The owner or operator may request a waiver from the

department from the required WOC time if the owner or operator has bench tested the actual cement batch and

blend using mix water from the actual source for the job, and determined that 8 hours is not required to reach a

compressive strength of 500 psig; and

(x) a copy of the cement job log for any cemented casing string in the well must be

available to the department at the well site during drilling operations, and thereafter available to the department

upon request. The owner or operator must provide such log to the department upon request at any time during

the period up to and including five years after the well is permanently plugged and abandoned consistent with

Part 555 of this Title. For multi-well pads, the five-year term specified in this paragraph shall begin after the last

well subject to Part 552 of this Title is permanently plugged and abandoned pursuant to a plugging permit

issued by the department.

(11) The surface casing must be run and cemented as soon as practicable after the hole has been

adequately circulated and conditioned. For environmental and/or public safety reasons, the department may

require that the owner or operator run a radial cement bond evaluation log or other evaluation approved by the

department to verify the cement bond on the surface casing. Surface casing must be set a minimum of 75 feet

below the base of potable fresh water, or 75 feet into competent bedrock, whichever is deeper. The base of

potable fresh water shall be determined and addressed as follows:

(i) For the first well on the pad or for a single well, the best available information (e.g.,

oil/gas well records, water well information, and pertinent local studies) must be used. Information gathered

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from the first well on the pad or from a single well will be used to confirm and or/refine the drilling, casing and

cementing program for subsequent wells on the pad or future nearby wells;

(ii) After the surface casing is run and cemented, the drilled intermediate hole up to and

including the surface casing seat will be geophysically logged to determine the possible existence of any potable

freshwater zones. Lack of such zones would confirm that all potable freshwater zones are behind the surface

casing; and

(iii) For a well where potable fresh water is found below the surface casing seat, an

external casing packer must be used on the intermediate string or other means approved by the Department must

be used to permanently isolate the potable freshwater zone from deeper, poor-quality water and/or gas-bearing

zones.

(iv) In lieu of the procedure set forth in (i) through (iii) above, an owner or operator may

propose, for department approval, to geophysically log the uncased surface hole to determine the base of

potable fresh water. The proposal must be based on best available information regarding shallow geology

including water and gas zones as well as anticipated surface-hole stability.

(12) As specified on a permit to drill, deepen, plug back and convert, the department must be

notified prior to surface casing cementing operations. Surface casing must be fully cemented to surface with

excess cement as follows. Cementing must be by the pump and plug method with a minimum of 25 percent

excess cement with appropriate lost circulation material, unless another amount of excess cement is approved

by the department.

(13) Intermediate casing must be installed in the well and run to the surface. The setting depth

and design of the casing must be determined by taking into account all applicable drilling, geologic and well

control factors. Additionally, the setting depth must consider cementing requirements for the intermediate

casing and the production casing. Any request to waive the intermediate casing requirement must be made in

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writing with supporting documentation and is subject to the department’s approval. Information gathered from

operations conducted on any single well or the first well drilled on a multi-well pad may be considered by the

department upon a request for a waiver of the intermediate casing requirement on subsequent wells in the

vicinity of the single well or subsequent wells on the same multi-well pad.

(14) As specified on a permit to drill, deepen, plug back and convert, the department must be

notified prior to intermediate casing cementing operations. Intermediate casing must be fully cemented to

surface with excess cement as follows. Cementing must be by the pump and plug method with a minimum of

25 percent excess cement unless a caliper log or other department-approved method is performed, in which case

10 percent excess will suffice.

(15) The owner or operator must run a radial cement bond evaluation log or other evaluation

approved by the department to verify the cement bond on the intermediate casing. Remedial cementing is

required if the cement bond is not adequate for drilling ahead (i.e., diversion or shut-in for well control).

(16) Production casing must be installed in the well and run to the surface. If installation of the

intermediate casing is waived by the department, then production casing must be fully cemented to surface. If

intermediate casing is installed, the production casing cement must be tied into the intermediate casing string

with at least 500 feet of cement above the intermediate casing seat measured using true vertical depth. Any

request to waive any of the cementing requirements of this paragraph must be made in writing with supporting

documentation, and must be approved by the department. The department will only consider a request for a

waiver if the open-hole wireline logs including a narrative analysis of such and all other information collected

during drilling from the same well pad or offsetting wells verify that migration of oil, gas or other fluids from

one pool or stratum to another will otherwise be prevented.

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(17) The owner or operator must run a radial cement bond evaluation log or other evaluation

approved by the department to verify the cement bond on the production casing. Remedial cementing is

required if the cement bond is not adequate to effectively isolate hydraulic fracturing operations.

(18) The installation of an additional cemented casing string(s) and/or liner(s), or both, in the

well, as deemed necessary by the department for environmental and/or public safety reasons, may be required at

any time.

(19) Under no circumstances should the annulus between the surface casing and the next casing

string be shut-in, except during a pressure test.

(20) If hydraulic fracturing operations are performed down casing, prior to introducing hydraulic

fracturing fluid into the well, the casing extending from the surface of the well to the top of the treatment

interval must be tested with fresh water, mud or brine to at least the maximum anticipated treatment pressure for

at least 30 minutes with less than a 10 percent pressure loss. This pressure test may not commence for at least 7

days after the primary cementing operations are completed on this casing string. A record of the pressure test

must be maintained by the owner or operator and made available to the department upon request. The actual

hydraulic fracturing treatment pressure must not exceed the test pressure at any time during hydraulic fracturing

operations.

(21) Prior to commencing hydraulic fracturing and pumping of hydraulic fracturing fluid, the

injection lines and manifold, associated valves, fracture head or tree and any other wellhead component or

connection not previously tested must be tested with fresh water, mud or brine to at least the maximum

anticipated treatment pressure for at least 30 minutes with less than a 10 percent pressure loss. A record of the

pressure test must be maintained by the owner or operator and made available to the department upon request.

The actual hydraulic fracturing treatment pressure must not exceed the test pressure at any time during

hydraulic fracturing operations.

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(22) The owner or operator must record the depths and estimated flow rates where fresh water,

brine, oil and/or gas were encountered or circulation was lost during drilling operations. This information and

the department’s Pre-Frac Checklist and Certification form including a treatment plan, must be submitted to and

received by the department at least 3 days prior to commencement of high-volume hydraulic fracturing

operations. The treatment plan must include a profile showing anticipated pressures and volumes of fluid for

pumping the first stage. It must also include a description of the planned treatment interval for the well (i.e., top

and bottom of perforations expressed in both True Vertical Depth and True Measured Depth).

(23) Hydraulic fracturing products other than those identified in the well permit application

materials may not be used without specific approval from the department.

(24) Diesel fuel may not be used as the base fluid for hydraulic fracturing operations.

(25) The owner or operator may conduct hydraulic fracturing operations on the applicable well

provided that notification to the department has been satisfied by submission of a completed and fully affirmed

Pre-Frac Checklist and Certification at least three days prior to the commencement of pumping the first stage

into the well to conduct hydraulic fracturing; and the relevant emergency management office r is notified prior

to the commencement of pumping the first stage into the well to conduct hydraulic fracturing.

(26) Hydraulic fracturing operations must be conducted as follows:

(i) secondary containment for fracturing additive containers and additive staging areas,

and flowback tanks is required. Secondary containment measures may include, as deemed appropriate by the

department, one or a combination of the following: dikes, liners, pads, impoundments, curbs, sumps or other

structures or equipment capable of containing the substance. Any such secondary containment must be

watertight and sufficient to contain 110 percent of the total capacity of the single largest container or tank

within a common containment area. No more than one hour before initiating any hydraulic fracturing stage, all

secondary containment must be visually inspected to ensure all structures and equipment are in place and in

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proper working order. The results of this inspection must be recorded and documented by the owner or

operator, and available to the department upon request;

(ii) at least two vacuum trucks, each with a capacity identified in the permit to drill,

deepen, plug back or convert, must be on standby at the well site during the pumping of hydraulic fracturing

fluid and during flowback;

(iii) hydraulic fracturing additives must be removed from the site if the site will be

unattended;

(iv) any hydraulic fracturing string, if used, must be either strung into a production liner

or run with a packer set at least 100 feet below the deepest cement top. An adequately sized, function-tested

relief valve and an adequately sized diversion line must be installed and used to divert flow from the hydraulic

fracturing string-casing annulus to a covered watertight steel tank or covered watertight tank made of another

material approved by the department in case of hydraulic fracturing string failure. The relief valve must be set

to limit the annular pressure to no more than 95 percent of the working pressure rating of the casings forming

the annulus. The annulus between the hydraulic fracturing string and casing must be pressurized to at least 250

psig and monitored;

(v) the pressure exerted on treating equipment including valves, lines, manifolds,

hydraulic fracturing head or tree, casing and hydraulic fracturing string, if used, must not exceed 95% of the

working pressure rating of the weakest component;

(vi) the hydraulic fracturing treatment pressure must not exceed the test pressure of any

given component at any time during hydraulic fracturing operations;

(vii) all annuli available at the surface must be continuously monitored in order to detect

pressure or flow, and the records of such monitoring maintained by the owner or operator and made available to

the department upon request; and

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(viii) hydraulic fracturing pumping operations must be immediately suspended if any

anomalous pressure and/or flow condition is indicated or occurring which is a significant deviation from either

the treatment plan (i.e., profile showing anticipated pressures and volume of fluid for pumping the first stage)

provided to the department with the Pre-Frac Checklist and Certification or any other anticipated pressure

and/or flow condition. Suspension of operations due to an anomalous pressure and/or flow condition is

considered a non-routine incident which must be reported to the department in accordance with section 560.5 of

this Part. In the case of suspended hydraulic fracturing pumping operations and non-routine incident reporting

of such, the owner or operator must receive department approval prior to recommencing hydraulic fracturing

activities in the same well.

(ix) The owner or operator must make and maintain a complete record of its hydraulic

fracturing operation, including during flowback, and provide such record to the department upon request at any

time during the period up to and including five years after the well is permanently plugged and abandoned

consistent with Part 555 of this Title. For multi-well pads, the five-year term specified in this paragraph shall

begin after the last well subject to Part 552 of this Title is permanently plugged and abandoned pursuant to a

plugging permit issued by the department. The record for each well must include pressure tests of hydraulic

fracturing treating equipment, wellhead components and casings, all types and volumes of materials, including

additives, listed by product name, pumped into the well, flowback rates, and the daily and total volumes of fluid

recovered during the first thirty days of flow from the well, with rates and volumes expressed in units specified

by the department. The record must also include a complete description of pressures exhibited throughout the

hydraulic fracturing operation and associated pressure recordings, charts and/or pressure profile. A synopsis of

the hydraulic fracturing operation must be provided in the appropriate section of the department’s Well Drilling

and Completion Report, which must be provided to the department within 30 days after completing the well in

accordance with section 554.7 of this Title.

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(27) Flowback water is prohibited from being directed to or stored in any on-site pit or

impoundment. Covered watertight steel tanks or covered watertight tanks constructed of another material

approved by the department are required for flowback handling and containment on the well pad. Flowback

water tanks, piping and conveyances, including valves, must be of sufficient pressure rating and be maintained

in a leak-free condition. Fluid transfer operations from flowback water tanks to tanker trucks must be

supervised at the truck and at the tank if the tank is not visible to the truck operator from the truck.

Additionally, during transfer operations, all interconnecting piping must be supervised if not visible to transfer

personnel at the truck and tank.

(28) The venting of any gas originating from the objective formation during flowbackmust be

through a flare stack at least 30 feet in height, unless the absence of H2S has been demonstrated at a previous

well on the same pad which was completed in the same producing horizon. Gas vented through the flare stack

must be ignited whenever possible. The stack must be equipped with a self-ignition device.

(29)A reduced emissions completion, with minimal venting and flaring (if any), must be

performed whenever gas is capable of being transported or marketed by connection of an available commercial

sales line, interconnecting gathering line and any necessary compressor station.

560.7 Waste Management and Reclamation

(a) Fluids must be removed from any on-site pit and the pit reclaimed no later than 45 days after

completion of drilling and stimulation operations at the last well on the pad, unless the department grants an

extension pursuant to paragraph 554.1(c)(3) of this Title. Flowback water must be removed from on-site tanks

within the same time frame.

(b) Removed pit fluids including used drilling mud must be disposed, recycled or reused as described in

the approved fluid disposal plan submitted pursuant to paragraph 554.1(c)(1) of this Title. Transport off-site of

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used drilling mud, flowback water and production brine by vehicle must be undertaken by a waste transporter

permitted pursuant to Part 364 of this Title.

(c) Drill cuttings must be disposed as described in the approved drill cuttings disposal plan submitted

pursuant to paragraph 554.1(c)(4) of this Title. Cuttings contaminated with oil-based mud or polymer-based

mud containing mineral oil lubricant must be contained and managed in a closed-loop tank system and may not

be buried on site, and must be removed from the site for disposal in a solid waste disposal facility. Transport

off-site of drill cuttings, except cutting samples collected upon the request of the department or for analytical

purposes by the owner or operator, and the pit liner by vehicle must be undertaken by a waste transporter

permitted pursuant to Part 364 of this Title. Disposal or on-site burial of cuttings associated with other drilling

fluids and any associated pit liner must conform to all applicable department regulations.

(d) The pit liner must be ripped and perforated prior to any department-approved burial on-site and to

the extent practical, excess pit liner material must be removed and disposed of properly.

(e) Permission of the surface owner is required for any department-approved on-site burial of cuttings

and pit liner, regardless of type of drilling proposed for use, listed byfluids used.

(f) Burial of any other solid waste on-site is specifically prohibited and all such waste must be removed

from the site and disposed of properly.

(g) A site-specific acid rock drainage mitigation plan must be prepared by the owner or operator,

approved by the department and followed for on-site burial of cuttings from any horizontal drilling in the

Marcellus if the owner or operator elects to bury these cuttings. The approved plan must be available on-site to

a department inspector while activities addressed by the plan are taking place.

(h) Unless otherwise approved by the department, well pads and access roads constructed for drilling

and production operations must be scarified or ripped to alleviate compaction prior to replacement of topsoil.

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Reclaimed areas must be seeded and mulched after topsoil replacement. Any proposal by the owner or operator

to waive these reclamation requirements must be accompanied by documentation of the landowner’s consent.

(i) Flowback water recovered after high-volume hydraulic fracturing operations must be tested for

naturally occurring radioactive material prior to removal from the site. Fluids recovered during the production

phase (i.e., production brine) must also be tested for naturally occurring radioactive material prior to removal.

Radiological analyses of flowback water and production brine must include analysis for combined radium (Ra-

226 and Ra-228) and other analytes as directed by the department. The soils adjacent to the flowback water and

production brine tanks must be measured for radioactivity upon removal of the tanks, and at such other times as

the department may require. For soil samples, analyses must at a minimum include gamma spectroscopy for all

naturally occurring gamma emitters including Ra-226 and Ra-228 (as determined from the presence of their

decay products).

(j) Production brine is prohibited from being directed to or stored in any on-site pit or freshwater

impoundment. Covered watertight steel, fiberglass or plastic tanks, or covered watertight tanks constructed of

another material approved by the department, are required for production brine handling and containment on the

well pad. Production brine tanks, piping and conveyances, including valves, must be constructed of suitable

materials, be of sufficient pressure rating and be maintained in a leak-free condition.

(k) Radiation surveys of the well head, piping, and flowback water and production brine tanks must be

performed using instrumentation, and on a schedule, prescribed by the department.

(l) Partial reclamation and final reclamation of any well pad and access road must be performed in

conformance with plans approved by the department.

1

Subparagraph (iv) of section 750-1.5(a)(6) is amended to read as follows:

(iv) injection into the well is approved by EPA if EPA approval is required, in accordance with 40 CFR

Parts 124.10, 144 and 146 (see section 750-1.24 of this Part).

A new Subpart 750-3 of this Part is adopted to read as follows

Subpart 750-3 High-Volume Hydraulic Fracturing (HVHF) Operations

(Statutory authority: Environmental Conservation Law, art. 3, titles 1, 3; art. 15, titles 3, 31; art. 17, titles 3, 5,

7, 8; art. 21; art. 70, title 1; art. 71, title 19; New York State Penal Code, arts. 175, 210; Public Health Law,

section 502; Federal Water Pollution Control Act, 33 USC 1251, et seq.)

750-3.1 Scope and purpose

(a) HVHF operations, as defined in section 750-3.2, require a SPDES permit.

(b) Unless in conflict, superseded or expressly stated otherwise in this Subpart, the provisions set forth in

Subpart 750-1 and Subpart 750-2 of this Part shall apply to HVHF operations.

750-3.2 Definitions

(a) For the purposes of this Subpart, the definitions of section 750-1.2 of this Part apply to the extent not

superseded by this Subpart. Terms not defined herein or in section 750-1.2 of this Part shall be defined by the

context in which they are used.

(b) Whenever used in this subpart, the following terms will have the meanings set forth below:

2

(1) 100-year floodplain means an area of special flood hazard, which is the land in the flood plain

within a municipality subject to a 1 percent or greater chance of flooding in any given year. The area

may be designated on a Flood Insurance Rate Map as a Zone A , AO, AH, A1-A30, AE, A99, AR,

AR/A1-A30, AR/AE, AR/AO, AR/AH, AR/A, VO, or V1-30, VE or V.

(2) Access road means a road constructed to the well pad that provides access during the drilling and

operation of the well.

(3) Aquifer means a zone of permeable, water-saturated material below the surface of the earth

capable of producing usable quantities of water.

(4) BUD means a Beneficial Use Determination issued by the Department, pursuant to Part 360 of

this Title.

(5) CAS Number means the Chemicals Abstract Service Registry number, a unique numeric

identifier for a substance, assigned by Chemical Abstracts Service, which is part of the American

Chemical Society.

(6) Casing means pipe, typically made of steel, placed in the drilled hole of a well of an oil and gas

well.

(7) Chemical additive means a substance composed of one or more chemical constituents that is

intentionally added to a base fluid.

(8) Chemical constituent means a discrete chemical with its own specific name or identity, such as a

CAS Number, which is contained within an additive product.

(9) Closed-loop tank system means a pitless drilling system where all drilling fluids and cuttings are

contained at the surface within piping, separation equipment and tanks.

(10) Comprehensive Stormwater Pollution Prevention Plan (SWPPP) means the combined

Construction SWPPP and HVHF SWPPP.

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(11) Construction Phase means the phase between commencement of surface soil disturbance

associated with the construction of access roads, well pads, and other appurtenances and Construction

Phase Completion.

(12) Construction Phase Completion means when (a) all construction activities in the Construction

SWPPP have been completed; (b) all the areas of disturbance have achieved final grade and measures

have been applied that will achieve final stabilization; and (c) all post-construction stormwater

management practices have been constructed in conformance with the Construction SWPPP and are

operational.

(13) Construction SWPPP means the stand-alone stormwater pollution prevention plan that includes

best management practices and other requirements to control the pollution of stormwater during both

construction of the well site and post-construction at the well site.

(14) Cuttings or samples means chips of rock cut by the drill bit and brought to the surface by the

drilling fluid.

(15) Drilling fluid means mud, water, brine, or other fluid, including air, pumped down the drill string

which acts as a lubricant and coolant for the drill bit and is used to carry rock cuttings back up the

wellbore. It may also be used for pressure control in the wellbore and to drive a mud motor and bit for

directional drilling.

(16) Final stabilization means all soil disturbance activities have ceased and a uniform, perennial

vegetative cover with a density of at least eighty (80) percent has been established or other equivalent

stabilization measures, such as sod, permanent landscape mulches, rock rip-rap or washed/crushed stone,

have been applied on all disturbed areas that are not covered by permanent structures, concrete or

pavement.

4

(17) Flood Insurance Rate Map (FIRM) means an official map of a community on which the Federal

Emergency Management Agency has delineated both the special flood hazard areas and the risk

premium zones applicable to the community.

(18) Flowback means liquids and solids produced during initial completion and clean up of the well

or clean up of a well following re-fracture or workover of a well.

(19) Formation fluids means fluids in a liquid or gaseous physical state, present within the pore

spaces, fractures, faults, caverns, or any other spaces of formations, whether or not naturally occurring

or injected therein.

(20) Freeboard means the distance between the maximum water surface elevation anticipated in

design and the top of retaining banks or structures. Freeboard is provided to prevent overtopping due to

unforeseen conditions.

(21) Fresh water supply means those groundwaters having a chloride concentration equal to or less

than 250 mg/L or a total dissolved solids concentration equal to or less than 1,000 mg/L.

(22) High-Volume Hydraulic Fracturing (HVHF) means 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 account

the sum of all water-based fluids, including fresh water and recycled flowback water, used in all HVHF

stages.

(23) High-Volume Hydraulic Fracturing Phase (HVHF Phase) means the phase following

Construction Phase Completion and through completion of Partial Site Reclamation. This phase

includes well drilling, high-volume hydraulic fracturing, and on-site handling and treatment of HVHF

wastewater produced until all wells planned for that well pad have been completed.

5

(24) High-Volume Hydraulic Fracturing Operations (HVHF Operations) means: (i) the Construction

Phase, (ii) the HVHF Phase, and (iii) the Production Phase.

(25) HVHF general permit means a SPDES permit issued pursuant to section 750-3.11 of this Part.

(26) HVHF SPDES permit means an individual SPDES permit for HVHF operations (individual

HVHF SPDES permit) or an HVHF general permit.

(27) HVHF SWPPP means the stand-alone stormwater pollution prevention plan required by a

SPDES permit that includes structural and non-structural best management practices and other activity-

specific requirements to control the pollution of stormwater during the HVHF Phase and the Production

Phase.

(28) HVHF wastewater means liquid waste consisting of one or more of the following: drilling

fluids, formation fluids, flowback, or production brine.

(29) Horizontal drilling means the deviation of the borehole from vertical so that the borehole

penetrates the objective formation in a manner parallel to the formation.

(30) Hydraulic fracturing means the act of pumping hydraulic fracturing fluid and a proppant into a

formation to increase its permeability.

(31) Hydraulic fracturing fluid means fluid used to perform hydraulic fracturing; includes the base

fluid and all chemical additives.

(32) Life of the well means the period of time from initial drilling of the well through plugging and

abandonment, in accordance with Part 555 of this Title, as adopted on XX, 20XX.

(33) Naturally Occurring Radioactive Materials (NORM) means the radioactivity that can exist

naturally in native materials, like some shales, and may be present in certain wastes from a well.

(34) Objective formation means the reservoir or target formation that the operator is trying to reach

and evaluate and/or complete when drilling a well.

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(35) Partial site reclamation means (a) when all of the equipment, materials and BMPs associated

with the HVHF Phase have been removed, (b) surface disturbances not associated with production

activities have been scarified or ripped to alleviate compaction prior to replacement of topsoil, and (c)

all the disturbed areas have been stabilized after topsoil replacement, in accordance with the Partial Site

Reclamation Plan submitted pursuant to Part 560.3(a)(17) of this Title, as adopted on XX, 20XX.

Partial reclamation and final reclamation of any well pad and access road must be done in conformance

with the plans approved by the department.

(36) Plugged and abandoned (plug and abandon) means the permanent abandonment of a well bore

including the placing of all bridges, plugs and fluids therein.

(37) Primary/Principal aquifers –

(i) Primary aquifers are highly productive aquifers presently being utilized as sources of

water supply by major municipal water supply systems.

(ii) Principal aquifers are aquifers known to be highly productive or whose geology suggests

abundant potential water supply, but which are not intensively used as sources of water supply by

major municipal systems at the present time.

(38) Product means an additive that is manufactured using precise amounts of specific chemical

constituents and is assigned a commercial name under which the material is sold or utilized.

(39) Production brine means liquids co-produced during oil and gas production.

(40) Production Phase means the phase following Partial Site Reclamation through the termination of

coverage under an HVHF general permit or termination of an individual HVHF SPDES permit. This

phase includes the production of natural gas and the on-site handling and treatment of production brine

at the well site.

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(41) Proppant means a material such as sand or ceramic particles that is carried in suspension by the

fracturing fluid and that serves to keep the induced fractures open when fracturing fluid is withdrawn

after a fracture treatment.

(42) Reserve pit means a lined, mud pit in which a supply of drilling fluid has been stored, or a waste

pit, usually an excavated pit.

(43) Reservoir, in relation to surface waters, means a ponded or impounded waterbody designated for

use as a public water supply, any portion of which is classified as A or AA, per Parts 800-941 of this

Title.

(44) Stage means isolation of a specific interval of the wellbore and the associated interval of the

formation for the purpose of maintaining sufficient fracturing pressure.

(45) Stimulation means the act of increasing a well’s productivity by artificial means such as

hydraulic fracturing, acidizing, and shooting.

(46) Storage means the holding of a material, container or equipment at a well site.

(47) TDS means Total Dissolved Solids.

(48) Temporary stabilization means that exposed soil has been covered with material(s) to prevent the

exposed soil from eroding. The materials can include, but are not limited to, mulch, seed and mulch,

and erosion control mats (e.g. jute twisted yarn, excelsior wood fiber mats).

(49) Unfiltered surface drinking water supplies means those public drinking water supplies that the

EPA or New York State Department of Health have determined meet the requirements of the "Interim

Enhanced Surface Water Treatment Rule" (IESWT Rule) for unfiltered drinking water supply systems.

The IESWT Rule is a December 16, 1998 amendment to the Surface Water Treatment Rule that was

originally promulgated by EPA on June 29, 1989. In New York State, this includes the New York City

Drinking Water Supply Watershed and the Syracuse Drinking Water Supply Watershed.

8

(50) Watershed means the region drained by, or contributing water to, a stream, lake, or other body of

water.

(51) Well pad means the area directly disturbed during drilling and operation of a gas well.

(52) Well site means the well pad and access roads, equipment storage and staging areas, vehicle

turnarounds, and any other areas directly or indirectly impacted by activities involving a well.

(53) Wellbore means a borehole; the hole drilled by the bit. A wellbore may have casing in it or it

may be open (uncased); or part of it may be cased, and part of it may be open.

(54) Wetland means any area regulated pursuant to Article 24 of the Environmental Conservation

Law and any other wetlands regulated under Section 404 of 33 U.S.C. 1251, et seq.

(55) Workover means any downhole operation in an existing well performed after initial completion

that is designed to sustain, restore or increase efficiency, make the well safer, or correct a known or

potential environmental hazard.

750-3.3 Prohibited Activities and Discharges

(a) The prohibitions in this section are in addition to those listed in section 750-1.3 of this Part, unless in

conflict, superseded or expressly stated otherwise in this section. Well pads for HVHF operations are

prohibited, and no SPDES permit will be issued authorizing any such activity or discharge:

(1) within 4,000 feet of, and including, an unfiltered surface drinking water supply watersheds;

(2) within 500 feet of, and including, a primary aquifer;

(3) within 100-year floodplains;

(4) within 2,000 feet of any public (municipal or otherwise) drinking water supply well, reservoir,

natural lake, man-made impoundment, or spring; and

9

(5) within 2,000 feet around a public (municipal or otherwise) drinking water supply intake in

flowing water with an additional prohibition of 1,000 feet on each side of the main flowing waterbody

and any upstream tributary to that waterbody for a distance of one mile from the public drinking water

supply intake; and

(6) within 500 feet of a private water well or domestic use spring, or water supply for crops or

livestock, unless the Department has granted a variance from the setback pursuant to subparagraph

560.4(c) of this Title, adopted on XX, 20XX.

(b) All distances noted above are measured from the closest edge of the HVHF well pad.

750-3.4 Requirement to obtain a permit

(a) The requirements in this section are in addition to those listed in section 750-1.4 of this Part, unless in

conflict, superseded or expressly stated otherwise in this section.

(b) HVHF operations cannot commence without a valid HVHF SPDES permit.

750-3.5 Exceptions

(a) The exceptions listed in this section are in addition to those listed in section 750-1.5 of this Part, except

paragraph 750-1.5(a)(6) of this Part, which is replaced by subdivisions (b), (c), (d) and (e) of this section.

(b) The injection of water, gas or other material through HVHF into a well, except a disposal well, to facilitate

production of gas resources, does not require a SPDES permit under ECL Article 17, Titles 7 or 8, or this Part if

the following conditions apply:

(1) the well used for injection is approved by authority of the department;

10

(2) the department determines that such injection will not result in the degradation of ground or

surface water resources;

(3) the injection does not result in a discharge at the surface; and

(4) injection into the well is approved by EPA if EPA approval is required in accordance with 40

CFR Parts 124.10, 144 and 146 (see section 750-1.24 of this Part).

(c) At a minimum, in order for the department to make a determination that the injection will not result in the

degradation of ground or surface water resources pursuant to paragraph 750-3.5(b)(2) of this Part:

(1) 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 ground surface and must be deeper than

1,000 feet below the base of a known freshwater supply; and

(2) the owner or operator must have measures in place to ensure compliance with the requirements

of paragraphs 750-3.7(k)(1), (2), (3), (4), (6), and (7) of this Part and subdivisions 750-3.7(l), (m), and

(n) of this Part.

(d) The department may change any previously-issued determination in the event that the permittee fails to

comply with any requirement described in this subdivision or such injection results in the degradation of ground

or surface water resources.

(e) An exception from requiring a SPDES permit pursuant to subdivision 750-3.5(b) of this Part only applies to

the injection of water, gas or other material through HVHF and does not apply to other activities or discharges

associated with HVHF operations.

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750-3.6 Individual HVHF SPDES Permit Application Requirements



(b) The owner or operator of an HVHF well site must submit an application for an HVHF SPDES permit,

which contains certifications that the owner or operator has measures in place to ensure compliance with

paragraphs 750-3.7(k)(1), (2), (3), (5), (6), and (7) of this Part and subdivisions 750-3.7 (l), (m), and (n) of this

Part.

(c) The owner or operator must submit documentation of the anticipated depth of the top of the objective

formation, and the depth of the base of the known freshwater supply, along the proposed length of the wellbore.

(d) The owner or operator must have an approvable plan identifying the ultimate disposition of HVHF

wastewater (Fluid Disposal Plan), in accordance with the requirements set forth in paragraph 554.1(c)(1) of this

Title, as adopted on XX, 20XX. In addition to the requirements of paragraph 554.1(c)(1) of this Title, as

adopted on XX, 20XX, the department will take into consideration compliance with any other law or regulation

before approving the Fluid Disposal Plan. As part of the approvable Fluid Disposal Plan, an applicant must also

submit an acceptable contingency plan, for disposition or disposal of such fluids that must be implemented

when the primary plan is unsafe or impracticable at the time of disposition or disposal.

(e) The owner or operator must develop and submit a final Comprehensive SWPPP to the department.

750-3.7 Application of standards, limitations and other requirements



(b) The owner or operator must ensure that the Comprehensive SWPPP is implemented. This includes any

12

changes made to the Comprehensive SWPPP.

(c) All BMPs must be inspected to ensure the effective implementation of the Comprehensive SWPPP.

Records must be kept of all inspections, conducted in accordance with applicable permit conditions.

(d) The owner or operator must keep the Construction SWPPP current so that it at all times accurately

documents the erosion and sediment control practices that are being used or will be used during construction,

and all post-construction stormwater management practices that will be used on the well site.

(e) The Construction SWPPP must include erosion and sediment control practices and post-construction

stormwater management practices.

(f) The owner or operator must ensure that all erosion and sediment control practices and all post-

construction stormwater management practices identified in the Construction SWPPP are maintained in

effective operating condition throughout the term of the HVHF SPDES permit.

(g) The owner or operator must ensure proper and adequate Construction Phase Completion. Final

stabilization must be achieved within four weeks of the implementation of final stabilization measures unless

otherwise approved by the department.

(h) Prior to terminating an HVHF SPDES permit, the owner or operator must ensure the continued

operation and maintenance of the post-construction stormwater management practices.

(i) The owner or operator must keep the HVHF SWPPP current so that at all times it accurately documents

the applicable BMPs for HVHF operations.

(j) At a minimum, the HVHF SWPPP must document that measures are in place to ensure compliance with

the requirements listed in subdivisions 750-3.7(k), (l), (m), (n), and (o) of this Part.

(k) The following conditions apply to all owners or operators during the HVHF Phase and Production

Phase:

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(1) The owner or operator’s disclosure of hydraulic fracturing fluid must be in accordance with

subparagraph 560.3(d) of this Title, as adopted on XX, 20XX.

(2) The owner or operator’s alternative analysis must be in accordance with subparagraph

560.3(d)(1)(vii) of this Title, as adopted on XX, 20XX. This includes documentation to the

department’s satisfaction, utilizing existing data and studies, that proposed chemical additives exhibit

reduced aquatic toxicity and pose at least as low a potential risk to water resources and the environment

as all known available alternatives; or documentation, to the Department’s satisfaction, that available

alternative products are not effective in achieving the desired results or economically feasible. The

owner or operator must use the proposed alternatives that satisfy the foregoing requirements.

(3) At the well site, the owner or operator must maintain a list of the chemical additives used on the well

site.

(4) The owner or operator must maintain a Fluid Disposal Plan, as required by 750-3.6(d) of this Part,

and any modifications to that Fluid Disposal Plan, including modifications that cover HVHF wastewater

from wells not originally identified.

(5) The owner or operator must conduct residential water well testing in accordance with the

requirements of subdivision 560.5(d) of this Title, as adopted on XX, 20XX, except that copies of test

results and documentation related to delivery of test results to owners of water wells must be sent to

New York State Department of Health.

(6) The owner or operator must remove all drilling fluid, formation fluid, or flowback from the well site

consistent with paragraph 560.6(b)(2) of this Title, as adopted on XX, 20XX, and subdivision 560.7(a)

of this Title, as adopted on XX, 20XX.

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(7) The owner or operator must provide, implement, and operate secondary containment measures for

activities that are conducted on the well site. Such secondary containment must, at a minimum, meet the

following requirements: they must (a) be designed and constructed in accordance with good engineering

practices, (b) be constructed, coated or lined with materials that are chemically compatible with the

environment and the substances to be contained, (c) be protected from heavy vehicle or equipment

traffic; and (d) have a volume of at least 110 percent of the single largest storage container or tank

within a common containment area. No more than one hour before initiating any HVHF stage, all

secondary containment must be visually inspected to ensure all structures and equipment are in place

and working order. The results of the inspection must be recorded and documented by the owner or

operator, maintained, and available to the department upon request.

(8) Within 12 months after all planned wells at the well pad have been completed, the owner or operator

must complete Partial Site Reclamation, as defined in this Part. After the completion of Partial Site

Reclamation, the owner or operator must continue to adhere to the reclamation measures in accordance

with the Partial Site Reclamation plan submitted pursuant to subdivision 560.7(l) of this Title, as

adopted on XX, 20XX.

(9) The owner or operator must have, and implement as necessary, a Spill Prevention Control and

Countermeasure Plan (SPCC) on the well site through the HVHF Phase and Production Phase. The

SPCC plan must include the Emergency Response Plan, as required by subsection 560.5(a) of this Title,

as adopted on XX, 20XX, an explanation of existing or planned material handling procedures, storage

requirements, secondary containment, equipment (e.g., diversion valves), and reporting, that are

intended to minimize spills or leaks at the well site. Quantities and types of equipment specified in the

SPCC must be present on the well site at all times.

15

(10) The owner or operator must plug and abandon the gas wells pursuant to Part 555 of this Title, as

adopted on XX, 20XX, prior to terminating an HVHF SPDES permit, unless otherwise approved by the

Department. Prior to plugging and abandonment, the owner or operator must notify the department and

modify the HVHF SWPPP to include stormwater controls during plugging and abandonment operations

and any reclamation done in accordance with subdivision 560.7(l) of this Title, as adopted on XX,

20XX.

(l) Flowback and production brine are prohibited from being directed to or stored in any reserve pit or

freshwater impoundment. For containment of flowback and production brine, unless otherwise approved by the

department, the owner or operator must follow the requirements set forth in paragraph 560.6(c)(27) and

subdivision 560.7(j) of this Title, as adopted on XX, 20XX.

(m) Any reserve pit, drilling pit or mud pit on the well pad must be maintained in a leak free condition and

constructed, for any number of wells, in accordance with the requirements set forth in paragraph 560.6(a)(4) of

this Title, as adopted on XX, 20XX. Additionally, such pits must be constructed, coated, or lined with materials

that are chemically compatible with the substance stored.

(n) A closed-loop tank system must be used instead of a reserve pit to manage drilling fluids and cuttings, in

cases set forth in paragraph 560.6(c)(7) of this Title, as adopted on XX, 20XX.

(o) The department may require that an approvable groundwater monitoring program be developed and

implemented.

750-3.8 Monitoring requirements in HVHF SPDES permits

(a) The requirements in this section are in addition to those listed in section 750-1.13 of this Part, unless

where in conflict, superseded or expressly stated otherwise in this section.

16

(b) All stormwater discharges must be monitored, recorded and reported in accordance with the terms and

conditions of an applicable HVHF SPDES permit to ensure effective operation of the stormwater controls.

(c) The HVHF SWPPP must include provisions to monitor and record:

(1) the volume of all water delivered for use at the well site from each source. Records must be

maintained identifying each truck/pipeline delivery of water and the source of the water;

(2) the volume of all recycled wastewater;

(3) the volume of water used for each HVHF stage. The volume must be metered with an automatic

continuous recording device (or its equivalent) that measures to within five percent (5%) of actual flow;

(4) the amounts of all chemical additives used for each HVHF stage.

(5) the volume of all flowback and production brine. The volume must be metered with an automatic

continuous recording device or equivalent that measures to within five percent (5%) of actual flow; and

(6) the volume of all sanitary and non-domestic wastewater produced onsite. The HVHF SWPPP must

also include a transportation record, which may also be required by Part 364 of this Title, of all sanitary

and non-domestic wastewater leaving the well pad. The transportation record must include the volume

of all sanitary and non-domestic wastewater shipped offsite by individual trucks and/or pipeline, as well

as the destination of the receiving facility(ies), and associated permit number if applicable.

(d) All records must be maintained at the well site and furnished to the department upon request.

(e) During HVHF operations, all stormwater discharges must be monitored, recorded and reported to

ensure effective implementation of the Comprehensive SWPPP, as well as compliance with applicable statutes,

regulations and any permit conditions.

17

750-3.9 Renewal of Existing HVHF SPDES permits



(b) Before an HVHF SPDES permit can be renewed, the owner or operator must provide documentation of

measures to ensure compliance with subdivision 750-3.6(d) of this Part.

750-3.10 Denial, Suspension or Revocation of HVHF SPDES permits



(b) The department may deny, suspend, or revoke an HVHF SPDES permit if the permittee violates any

provision of this Subpart.

750-3.11 HVHF general permit

(a) The requirements of this section are in addition to those listed in sections 750-1.21, 750-3.7, 750-3.8,

and 750-3.11 of this Part, unless in conflict, superseded or expressly stated otherwise in this section.

(b) Discharges from HVHF operations may be authorized in accordance with an HVHF general permit.

(c) An HVHF general permit does not authorize the discharge of hazardous substances (as listed in Part 597

of this Title) or petroleum.

(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 SPDES permit.

At a minimum, HVHF operations sited within the following buffers cannot be authorized by a HVHF GP

(calculated from the closest edge of the well pad):

18

(e) The following non-stormwater discharges are ineligible for coverage under an HVHF general permit and

must be authorized under a separate SPDES permit, or be discharged to a sanitary sewer in accordance with

applicable pretreatment requirements, or be transported off-site for proper disposal:

(1) discharges of sanitary wastewater;

(2) vehicle and equipment washwater, including tank cleaning operations or substances (hazardous,

non-hazardous, etc.) resulting from an on-site spill and materials collected in drip pans;

(3) washwaters from material handling and processing areas; or

(4) washwaters from drum, tank, or container rinsing and cleaning.

(f) The following activities are ineligible for coverage under an HVHF general permit and would require

authorization under an individual SPDES permit:

(1) Construction and use of a centralized flowback impoundment;

(2) Construction activities related to HVHF operations:

(i) where the discharges from the construction activities are tributary to waters of the state

classified as AA or AA-s; and

(ii) which disturb land with no existing impervious cover; and

Principal Aquifer 500 feet

Wetland

300 feet

Perennial or intermittent streams, as described in Parts 800-941

of this Title, storm drains, lakes, or ponds

P

300 feet

19

(iii) which are undertaken on land with a Soil Slope Phase that is identified as an E or F, or

the map unit name is inclusive of 25% or greater slope, on the United States Department of

Agriculture (USDA) Soil Survey for the surface area where the disturbance will occur.

(3) HVHF operations that adversely affect a listed or proposed to be listed endangered or threatened

species or its critical habitat;

(4) HVHF operations that adversely affect a property that is listed or is eligible for listing on the

State or National Register of Historic Places (Note: includes Archeological sites), unless there are

written agreements in place with the NYS Office of Parks, Recreation and Historic Preservation

(OPRHP) or other governmental agencies to mitigate the effects, or there are local land use approvals

evidencing the same;

(g) The following stormwater discharges cannot be authorized by an HVHF general permit:

(1) Contaminated stormwater discharges from drilling operations that are subject to nationally

established Best Available Technology Economically Achievable (BAT) or Best Practicable Control

Technology Currently Available (BPT) guidelines found at 40 CFR Part 435;

(2) Discharges from HVHF operations that are mixed with sources of non-stormwater other than

those expressly authorized under either the HVHF general permit or a different SPDES permit;

(3) Discharges from HVHF operations where a SPDES individual or general permit located at the

HVHF operation site has been terminated, revoked, suspended, or denied, or which have been issued an

individual or alternative general permit;

(4) Discharges from HVHF operations, which either cause or contribute to a violation of water

quality standards adopted pursuant to the ECL and its accompanying regulations;

(h) Obtaining coverage under an HVHF general permit:

(1) All of the following must be satisfied in order for an owner or operator to be authorized to

20

discharge under an HVHF general permit:

(i) Where required, all necessary department permits subject to the Uniform Procedures Act

have been obtained, unless the department determines otherwise pursuant to paragraph

621.(3)(a)(4) of this Title;

(ii) Preparation of the final Comprehensive SWPPP;

(iii) The owner or operator must submit certifications to the department that the owner or

operator has measures in place to ensure compliance with in paragraphs 750-3.7(k)(1), (2), (3), (4),

(6), and (7) of this Part and subdivisions 750-3.7(l), (m), and (n) of this Part.

(iv) The owner or operator must also submit documentation to the department of the

anticipated depth of the top of the objective formation and the depth of the base of the known

freshwater supply, along the proposed length of the wellbore.

(v) Preparation of an approvable plan identifying the ultimate disposition of HVHF

wastewater (Fluid Disposal Plan), in accordance with the requirements set forth in paragraph

554.1(c)(1) of this Title, as adopted on XX, 20XX. In addition to the requirements of paragraph

554.1(c)(1) of this Title, as adopted on XX, 20XX, the department will take into consideration

compliance with any other law or regulation before approving the Fluid Disposal Plan. As part of

the approvable Fluid Disposal Plan, an applicant must also submit an acceptable contingency plan,

for disposition or disposal of such fluids that must be implemented when the primary plan is unsafe

or impracticable at the time of disposition or disposal ; and

(vi) A complete Notice of Intent has been submitted to the department.

(2) An owner or operator may not commence any construction activities related to HVHF operations

until its authorization to discharge under the HVHF general permit is effective.

(3) Coverage under an HVHF general permit authorizes stormwater discharges from construction

21

activities only from those areas of disturbance that are identified in the Notice of Intent. If an owner or

operator wishes to have stormwater discharges from future or additional areas of disturbance authorized,

the owner or operator must submit an amendment to the Notice of Intent that addresses the future or

additional areas of disturbance, unless otherwise notified by the department.

(i) Duration of an HVHF general permit:

(1) The duration of an HVHF general permit may be no more than five (5) years from its effective date.

(2) In the event a new HVHF general permit is not issued prior to termination of the current HVHF

general permit, the owner or operator may continue to operate and discharge in accordance with the

terms and conditions of the current HVHF general permit until such time as a new HVHF general permit

is issued. Unless otherwise notified by the department in writing, an owner or operator with coverage

under the current HVHF general permit that seeks authorization under the new HVHF general permit

must submit a new Notice of Intent in accordance with the terms of such new HVHF general permit.

(3) Coverage for new owners or operators will not be accepted under any continued HVHF general

permit.

(j) Transfer of coverage under an HVHF general permit:

(1) If there is a change in the owner or operator with coverage under the HVHF GP, the original owner

or operator must notify the new owner or operator, in writing, of the requirement to obtain general

permit coverage. Once the new owner or operator obtains general permit coverage, the original owner

or operator must then submit a completed Notice of Termination to the department with the name and

permit identification number of the new owner or operator.

(2) General permit coverage for the new owner or operator will be effective as of the date the

department receives a completed Notice of Intent, provided the original owner or operator had coverage

22

under an HVHF general permit as of the date the department receives the Notice of Intent from the new

owner or operator.

(3) If the original owner or operator maintains control or ownership of a portion of the HVHF operation,

the owner or operator must maintain its coverage under an HVHF general permit.

(k) Renewal of coverage under an HVHF general permit:

(1) Before coverage under an HVHF general permit can be renewed, the owner or operator must provide

documentation of compliance with subdivision 750-3.6(d) of this Part.

(l) Denial, suspension or revocation of coverage under an HVHF general permit:

(1) As set forth in subdivision 750-1.21(e) of this Part, the department may require any owner or

operator authorized to discharge in accordance with an HVHF general permit to apply for and obtain an

individual SPDES permit or apply for authorization to discharge in accordance with another general

permit.

(2) The department may suspend, terminate, or deny an owner’s or operator’s coverage under an HVHF

general permit if the department determines that the Comprehensive SWPPP does not meet any HVHF

general permit requirements.

(3) Upon a finding of significant non-compliance with the Comprehensive SWPPP, the department may

order an immediate stop to all activity at the well until the non-compliance is remedied. The stop work

order must be in writing, describe the non-compliance in detail, and be sent to the owner or operator.

An owner or operator must comply with all terms of a stop work order issued pursuant to this paragraph.

(m) Unless and until a fee is promulgated specifically for an HVHF general permit, HVHF operations are

considered a SPDES permit for stormwater discharges from construction activity for purposes of assessing

SPDES general permit fees.

23

(n) Coverage under an HVHF general permit may be terminated by the owner or operator upon:

(1) plugging and abandonment of all wells in accordance with Part 555 of this Title, as adopted on XX,

20XX;

(2) transfer of coverage under an HVHF general permit where all other conditions in this general permit

for the transfer of coverage have been met;

(3) authorization for the discharge under an alternative SPDES permit or an individual SPDES permit is

obtained; or

(4) as otherwise approved by the department.

750-3.12 Disposal of HVHF wastewater

(a) All HVHF wastewater must be treated, recycled, or otherwise properly disposed through the life of the

well in accordance with all applicable federal and state laws.

(b) The discharge of flowback to the ground is prohibited. The discharge of drilling fluids, formation fluids

and production brine to the ground is prohibited, except in accordance with the terms and conditions of a BUD.

(c) Requirements for acceptance, treatment, and disposal of HVHF wastewater at a POTW:

(1) HVHF wastewater may be accepted only by a POTW that has a valid SPDES permit and a

pretreatment program approved by EPA or a mini-pretreatment program approved by the department,

and is permitted by the department to accept HVHF wastewater.

(2) Prior to being permitted to accept HVHF wastewater, the POTW must perform a headworks

analysis for the HVHF wastewater and submit the analysis for review and approval by the department

and EPA. The headworks analysis must meet the requirements of 40 CFR Part 403, including a

representative assay of the concentrations of chemical constituents present, as well as other parameters

24

that may be present in the HVHF wastewater. The headworks analysis must demonstrate that the HVHF

wastewater will not cause a violation of the POTW's effluent limits or sludge disposal criteria, and will

not result in pass through of substances present in HVHF wastewater, or adversely affect the POTW's

treatment processes.

(3) Once the headworks analysis is approved by both the department and EPA, the department shall

include in the POTW’s SPDES permit, or may modify the POTW’s existing SPDES permit to include

appropriate monitoring, recording, and reporting requirements, and effluent limitations associated with

HVHF wastewater.

(4) Any HVHF wastewater to be treated by the POTW must be introduced to the headworks of the

POTW, unless otherwise permitted by the department.

(5) For each introduction of HVHF wastewater to the headworks of the POTW, the following

documentation must be maintained by the POTW:

(i) the source well of the HVHF wastewater, including the identity of the HVHF well owner or

operator;

(ii) a list of chemical constituents used in HVHF, along with a representative assay of the

concentrations of chemical constituents present, as well as other parameters that may be present;

and

(iii) the volume of wastewater to be accepted by the POTW.

(6) Prior to being permitted to accept HVHF wastewater the POTW must demonstrate that it has an

approved method for transport and disposal of residuals in compliance with Parts 360, 364, 380 and 381

and subdivision 750-2.8(e) of this Part.

25

(7) All POTWs shall provide adequate notice to the Department and to EPA of the following:

(i) Any new introduction of pollutants to the POTW from an indirect discharger that would be

subject to section 301 or 306 of the CWA if it were directly discharging those pollutants;

(ii) Any substantial changes in the volume or character of pollutants being introduced into that

POTW by a source introducing pollutants into the POTW at the time of issuance of the permit

(iii) For the purposes of this paragraph, adequate notice shall include information on:

(a) the quality and quantity of effluent introduced into the POTW; and

(b) any anticipated impact of the change on the quantity or quality of effluent to be

discharged from the POTW.

(d) Requirements for offsite acceptance, treatment, recycling,and disposal of HVHF wastewater at a

privately owned industrial wastewater treatment facility:

(1) HVHF wastewater may be accepted only by a facility that has a valid SPDES permit and is permitted

by the department to accept HVHF wastewater.

(2) Prior to being permitted to accept HVHF wastewater, the facility must complete an approvable

treatability analysis for the HVHF wastewater. The treatability analysis must demonstrate that the

HVHF wastewater will not cause a violation of the facility’s effluent limits or sludge disposal

criteria, and will not result in pass through of substances present in HVHF wastewater, or adversely

affect the facility’s treatment processes. The treatability analysis must include the following:

(i) each source of HVHF wastewater to be accepted and the identity of each HVHF well owner

or operator;

(ii) the total volume of HVHF wastewater to be accepted by the facility from each source of

HVHF wastewater, and the proposed rate of introduction into the facility;

26

(iii) for each identified source of HVHF wastewater, a representative assay of the concentrations

of chemical constituents present, as well as other parameters that may be present in the HVHF

wastewater;

(iv) the expected effluent concentrations of all chemical constituents present, as well as other

parameters that may be present in the HVHF wastewater; and

(v) the volume of treated HVHF wastewater to be discharged as effluent and the volume of

treated HVHF wastewater to be generated for reuse.

(3) Once the treatability analysis is approved by the department, the department shall include in the

facility’s SPDES permit, or may modify the facility’s existing SPDES permit to include, appropriate

monitoring, recording and reporting requirements, and effluent limitations associated with HVHF

wastewater.

(4) Any HVHF wastewater to be treated by the facility must be introduced to the headworks of the facility,

unless otherwise permitted by the department.

(5) For each introduction of HVHF wastewater to the headworks of the facility, the following

documentation must be maintained by the facility:

(i) the source well of the HVHF wastewater, including the identity of the HVHF well owner or

operator;

(ii) a list of all chemical constituents used in HVHF, along with a copy of the representative assay

required in subparagraph (2) (iii) above; and

(iii) the volume of wastewater to be accepted by the facility.

27

(6) Prior to being permitted to accept HVHF wastewater, the facility must also demonstrate that it has an

approved method for transport and disposal of residuals in compliance with Parts 360, 364, 380 and

381 and subdivision 750-2.8(e) of this Part.

(e) Requirements for onsite treatment and recycling of HVHF wastewater:

(1) Facilities constructed specifically for the onsite treatment of HVHF wastewater are prohibited

from directly discharging to the waters of the State pursuant to 40 CFR Part 435. These onsite facilities

are not eligible to obtain a SPDES permit. All HVHF wastewater accepted and treated by these onsite

facilities must be either reused, as approved by the department, or transported for offsite disposal at a

permitted facility.

(2) Prior to acceptance of any HVHF wastewater , the onsite facility must demonstrate to the

department that it has an approved method of disposal of residuals in compliance with Parts 360, 364,

380, and 381 of this Title and subdivision 750-2.8(e) of this Part.

(f) Requirements for deep well injection of HVHF wastewater:

(1) HVHF wastewater may be accepted only by a deep well injection facility that has a valid SPDES

permit and is permitted by the department to accept HVHF wastewater.

(2) The owner or operator of the disposal well must obtain a permit, or a modification to an existing

permit, under the EPA Underground Injection Control (UIC) program for disposal wells prior to

applying for a SPDES permit, or a modification to an existing SPDES permit, in accordance with this

subpart and subpart 750-1.

(3) The SPDES permit application for a new deep well injection facility or modification of an existing

deep well injection facility SPDES permit to accept HVHF wastewater must include the following:

28

(i) each source of HVHF wastewater and the identity of each HVHF well owner or operator;

(ii) the total volume of HVHF wastewater from each source of HVHF wastewater, and the

proposed rate of introduction into the disposal well;

(iii) for each identified source of HVHF wastewater, a representative assay of the concentrations

of chemical constituents present, as well as other parameters that may be present in the HVHF

wastewater;

(iv) geotechnical information regarding the ability of the disposal stratum to accept and retain the

injected fluid, including an estimate of available capacity;

(v) a water quality analysis of the receiving stratum for chemical constituents present, as well as

other parameters that may be present in the HVHF wastewater; and

(vi) injection well construction and operational control information showing that the well meets

the applicable EPA UIC injection well standards as promulgated under 40 CFR Parts 144-148

and sections 1423 and 1425 of the Safe Drinking Water Act.

(4) The SPDES permit application for an existing deep well injection facility that has already been

approved to accept HVHF wastewater, but wishes to accept another source of HVHF wastewater must

include the items listed in paragraph 750-3.12 (f)(3).

(5) In addition to the requirements of the EPA UIC program, the department may propose appropriate

monitoring, recording and reporting requirements and effluent limitations in the SPDES permit,

including:

29

(i) effluent limitations, pursuant to Parts 701-706 of this Title for chemical constituents present,

as well as other parameters that may be present in the HVHF wastewater;

(ii) the proposed well construction and operation program; and

(iii) installation of upgradient and downgradient monitoring wells and a monitoring program

with periodic monitoring for chemical constituents present, as well as other parameters that may

be present in the HVHF wastewater.

6 NYCRR Parts 52, 190, 550-556, 560, and 750

HIGH-VOLUME HYDRAULIC FRACTURING

ASSESSMENT OF PUBLIC COMMENT

This assessment responds to the consolidated comments received on the draft regulations

for Parts 52, 190, 550-556, 560, 750-1, and 750-3 of Title 6 of the New York State Code of

Rules and Regulations (NYCRR). The revised draft Supplemental Generic Environmental

Impact Statement (rdSGEIS) was released for public comment on September 7, 2011. On

September 28, 2011, the New York State Department of Environmental Conservation

(Department) released for public comment draft regulations concerning high-volume hydraulic

fracturing and the State Pollutant Discharge Elimination System (SPDES) General Permit for

Stormwater Discharges from High-Volume Hydraulic Fracturing (HVHF General Permit).

Public hearings were held concurrently on all of these documents and the combined public

comment period was held open until January 11, 2012. In total, the Department received over

66,000 individual public comments on these documents, from postal mail, electronic

submissions, and speakers at public hearings held in 2011.

The Department processed every comment and comments received equal consideration.

The Department broke down comment submissions into smaller, more manageable segments.

Similar segments were combined into one consolidated statement. Therefore, one consolidated

statement could represent portions of identical or similar comments received from a number of

commentors. Of the 66,000 comments, there are more than 650 consolidated comments on the

draft regulations to which the Department provides responses below.

The Department received comments from many diverse groups and individuals including

mineral rights owners, federal, state, and local agencies, environmental organizations, landowner

coalitions, industry representatives, and legislators. During preparation of the proposed revised

regulations, the Department incorporated suggestions made by the public (both with respect to

the proposed regulations and the 2011 rdSGEIS).

The Assessment of Public Comment (APC) presents and responds to all of the

consolidated comments on the proposed regulations that were received during the public

comment period. The consolidated comments and responses are grouped into several categories:

categories 82-89 regarding the proposed mineral resources regulations; category 90 regarding the

proposed water resources regulations; categories 91 and 92 regarding the proposed lands and

forests, fish, wildlife and marine resources regulations; and category 114 regarding general

comments on the proposed rulemaking.

The Department will accept additional public comment on the proposed revised

regulations, and will prepare a subsequent assessment of public comment in response to those

comments.

82: Part 551, Reports and Financial Security

Comment 3109:

Part 551.1(a) should be revised to require disclosure by applicants of pending and final actions

concerning violations in other states. Applicants that have been fined or suspended from drilling

in other states should not be able to simply move to New York State and begin operating.

Response 3109:

The Department disagrees that the proposed rules should be amended as suggested in the

comment. Previous violations and penalties assessed in other states are relevant to the fitness of

an applicant for a Department issued permit. However, the compliance history of an applicant is

fact specific and cannot be addressed with a broad prohibition against operating in New York

based either on a pending enforcement action or a final one. The Department’s Record of

Compliance policy, available on the Department’s website at:

http://www.dec.ny.gov/regulations/25244.html, provides information on how an applicant’s

compliance history factors into a permitting decision by the Department.

Comment 3110:

Parts 551.1 through 551.3: Reporting appears to be the responsibility of the gas companies.

Objective, disinterested assessment and reporting should instead be mandated.

Response 3110:

The reports required by existing regulations at 6 NYCRR Section 551.1 through 551.3, which

include organization reports, production reports, and well completion reports should be

completed by the person(s) most knowledgeable of and responsible for the relevant activity.

Reports submitted to the Department are signed under penalty of perjury, and it is therefore more

reasonable to require those reports to be submitted by the responsible party.

Comment 3111:

http://www.dec.ny.gov/regulations/25244.html

Part 551.4(a) should be revised to state that an owner of an oil or gas well must file financial

security documentation with the Department as part of the well permit application and that no

surface disturbance for a new well pad or well drilling for an existing pad can occur until such

financial security is in place and deemed acceptable by the Department.

Response 3111:

The proposed revisions is not necessary, as paragraph 552.2(a) already requires financial security

to be in place prior to issuance of a permit to drill. Section 552.1 (a), under the proposed rules,

will also make clear that no surface disturbance is allowed prior to obtaining a permit from the

Department.

Comment 3112:

Part 551.5: For wells up to 6,000 feet deep, the per-well and total cap limits for financial

security are too low and should be increased.

Response 3112:

The proposed regulatory changes to Part 551 included removal of the per-well and total cap for

wells that exceed 6,000 feet in true measured depth. For wells less than 6,000 feet deep, to

which the comment pertains, the amount of financial security is set in statute at ECL 23-

0305(8)(k). Any change to the amount of financial security needed for wells less than 6,000 feet

deep would therefore require legislative action.

Comment 3113:

Parts 551.5 and 551.6: Regardless of well depth and type, the amount of financial security

required should be the full cost of plugging and abandoning all of the wells involved. There

should be no cap, there should be no discounts for multiple wells, and the calculated cost should

take inflation and future prices into account. The State already has too many abandoned and

unplugged wells and inadequate financial resources to address them.

Response 3113:

See response to Comment 3112.

Comment 3114:

Part 551.6: Financial security requirements should be based on more than the anticipated costs of

plugging and abandoning the wells and should include the costs of other liabilities such as

potential remediation, cleanup, accidents, and spills and releases.

Response 3114:

The Department disagrees, as the requirement for financial security stems from ECL 23-

0305(8)(e) which states that prior to the commencement of drilling a well, a well operator shall

provide financial security “conditioned upon the performance of said operator’s plugging

responsibilities with respect to said well.” The statute does not authorize the Department to set

the amount of financial security required for deep wells to serve as a contingency fund in the

event of a contamination event.

Comment 3115:

Part 551.6: As an alternative to or in addition to increasing financial security to cover the costs of

potential liabilities beyond plugging and abandonment (such as remediation, accidents, and spills

and releases), well operators should be required to purchase insurance to cover those potential

liabilities. The up-front cost of insurance might be more incentive to operate in an

environmentally responsible manner and might be a more reliable form of compensation if a

drilling company becomes insolvent.

Response 3115:

See response to Comment 3114. The suggestion in the comment is beyond the scope of the

proposed rulemaking.

Comment 3116:

Part 551.6: The Department should not be the only entity involved in determining that the

financial security required and obtained by operators is adequate.

Response 3116:

The Department disagrees, as ECL Article 23 indicates that the bond or other security provided

must be acceptable to the Department.

Comment 3117:

Part 551.6: The $2 million cap on financial security requirements for wells deeper than 6,000

feet is too low. There should be no cap (or the cap should be raised) and the amount required

should be the full cost of plugging and abandoning all of the wells involved. With financial

security limits for 6,000+-foot wells of $250,000 per well and $2,000,000 total, operators with

more than eight wells would have no additional liability or incentive to responsibly plug and

abandon wells beyond the first eight. As well, $2,000,000 is inadequate to pay for a major

drilling mishap or the future financial and environmental costs of abandoned unplugged wells.

(The amounts being required by the Delaware River Basin Commission for spills and releases

are $5 million for each well and $25 million for multiple wells.)

Response 3117:

See response to Comment 3112. The proposed rule would require the well operator to file

financial security based upon the anticipated costs of plugging and abandoning the well. Well

operators will need to supply information to the Department concerning the cost of plugging and

abandoning the well in order for the Department to determine an acceptable amount of financial

security.

Comment 3118:

Part 551.6: In addition to the financial security required, each well should be assessed additional

fees payable to the state that could be used for purposes such as a cleanup fund (to clean up

abandoned high-volume hydraulic fracture well sites where the responsible party is bankrupt or

closed); additional state monitoring and enforcement personnel; or a land conservation fund (for

the state to purchase additional lands to offset habitat destruction and fragmentation caused by

high-volume hydraulic fracturing).

Response 3118:

Assessment of a new fee is beyond the scope of the proposed rule. See also response to

Comments 3114 and 3115.

Comment 3119:

Part 551.6: Financial security should be required for plugging and abandoning wells of any

depth, not just those that are 6,000 feet or more in depth.

Response 3119:

There are financial security requirements for ECL 23 wells of any depth. See ECL 23-

0305(8)(k) and the responses to Comments 3112 and 3114.

Comment 3120:

Part 551.6: The State should be named the insured for an environmental liability policy of not

less than $2,000,000 for each well.

Response 3120:

The Department does not currently accept insurance as a means of financial security. ECL

Article 23 indicates that bonds, cash or negotiable bonds of the United States Government are

acceptable forms of financial security.

Comment 3121:

Bureau of Oil and Gas Regulation officials should be directed to prevent financially unqualified

owners from obtaining oil or gas wells through transfer requests.

Response 3121:

The current rulemaking does not include proposed rules related to the transfer of wells.

However, the commenter should note that ECL 23-0305(8)(e) provides that an operator is not

relieved of its well plugging responsibilities unless a subsequent operator has furnished the

appropriate bond or substitute and until the Department has approved the transfer of plugging

responsibilities to the subsequent operator.

Comment 3122:

The required financial security should be in the form of insurance or money placed in an escrow

account overseen by the State. It should not be in the form of a security bond, which is only as

good as the financial state of a company. In case of an extreme accident that tests the economic

viability of a company, a security bond can be withdrawn by the issuing bank or company.

Response 3122:

ECL Article 23 authorizes the use of bonds. The proposed rules do not propose to change the

types of financial security accepted by the Department. See response to Comment 3120.

Comment 3390:

Instead of the financial security requirements proposed in Part 551.6, a bond to offset the cost of

plugging the gas well should be posted for each gas well drilled, to ensure that taxpayers will not

have to pay later for inadequately plugged and abandoned wells.

Response 3390:

Bonds are routinely accepted by the Department as a means of financial security to ensure that

well operators satisfy their well plugging responsibilities. See also response to Comment 3117.

Comment 6280:

Part 551 should include liability clauses in its regulation of the hydraulic fracturing industry.

Any company, party, or entity involved in the process must be held accountable for cleaning up

any environmental contamination, fully restoring the site to its previous condition, and bearing

all expenses and responsibilities of such. As well, the State’s costs for monitoring the industry

should be billed directly to the drilling companies.

Response 6280:

The Department disagrees that Part 551 should be amended as suggested in the comment.

Existing Section 554.1 already prohibits pollution of the land and/or surface or ground fresh

water from exploration or drilling. Operators are also held responsible, pursuant to ECL Article

71, for failing to comply with the rules and regulations of the Department as well as any

condition of a Department-issued permit. Therefore, the ECL and the implementing regulations

already address accountability for contamination and reclamation of the land surrounding the

well.

Comment 6283:

The Department’s proposal to amend Part 551 of the existing regulations to eliminate the

maximum bond required for plugging and abandonment of an individual well and a two million

dollar cap on bonding for operators that operate multiple wells (i.e., blanket bonding) goes too

far. Although Industry supports reasonable bonding requirements, it is unreasonable to eliminate

bonding limits and not encourage blanket bonds or other funding mechanisms that will be more

cost-effective to industry. Shale gas wells are expected to be productive for decades. As such,

requiring individual bonding for each well will tie up capital unnecessarily. Bonding is only

necessary where an operator defaults on its plugging and abandonment obligations. In recent

times, there have been no such defaults. Accordingly, the proposed amendment of Part 551 is

unnecessary and unreasonable. Moreover, the elimination of a limit on the bond required per

well and the total bonding required per operator is inconsistent with the bonding requirements of

neighboring states, which will render New York non-competitive. For example, Pennsylvania is

currently considering increasing the blanket bonding required to $600,000. Ohio and West

Virginia require $15,000 and $60,000 bonds, respectively. In addition, given the longevity of

bonding with wells that may last for three decades or longer, it is important to provide

alternatives for those operators that can meet a financial test for financial security. Accordingly,

Part 551.6 should be revised to state: The owner of an oil , gas or solution mining , storage,

stratigraphic, geothermal or disposal well that exceeds or that is expected to exceed 6,000 feet in

true measured depth must file financial security for that well in an amount based upon the

anticipated costs of plugging and abandoning that well to the satisfaction of the department in

accordance with Part 555 of this Title, up to $250,000. However, the owner is not required to file

financial security under this section exceeding $600,000, regardless of the number of wells

described in this section that the owner may have. Any owner that is subject to the financial

security requirements of this section may qualify based upon the financial test and guarantee

provided in Section 373-2.8(d)(5).

Response 6283:

The Department disagrees that the financial test and guarantee utilized in the hazardous waste

program is appropriate for use in the Oil, Gas and Solution Mining program. ECL Article 23

directs that a bond, cash or negotiable bonds of the U.S. Government, in a form approved by the

Department, shall be provided to ensure compliance with an operator’s well plugging

responsibilities and the proposed rules do not include a change in the types of financial security

acceptable to the Department. As to the amount of financial security required, the Department

disagrees that the operator cap currently set at $2 million should be reduced to $600,000. The

Department proposed to remove the cap to account for the fact that drilling of deep wells is

expected to be more common than in previous years. Estimates of potential drilling activity to

target low-permeability reservoirs also suggest that the number of applications for a Permit to

Drill submitted to the Department will far exceed existing levels of permitting. The existing

operator cap of $2 million presented a risk that the amount of financial security held by the

Department would not be commensurate with the number of active wells operated by any one

entity. In some instances, $2 million may be appropriate as an operator cap, and the Department

retains the discretion to utilize an operator cap.

Comment 6580:

Part 551.1(a)(2): Disposal wells with a true vertical depth shallower than 500 feet should also be

subject to reporting requirements.

Response 6580:

The proposed changes to 551.1(a)(2) were intended to clarify that an organizational report is

required for all wells regulated under the Oil, Gas and Solution Mining Law. As the Department

issues permits for initial well drilling as well as for wells plugged back, deepened, and converted,

the proposed rules simply spells this out in greater detail. The disposal wells called out in

551.1(a) refers to wells drilled for the injection of brine. ECL 23-0305(14) expressly limits the

Department’s jurisdiction in the Oil, Gas and Solution Mining Law to brine disposal wells drilled

deeper than five hundred feet. Therefore, the change suggested in the comment is beyond the

scope of the regulatory changes as it would require legislation.

Comment 7793:

Part 551.6: The true costs of plugging and abandoning the wells should be required to be

calculated based on third-party contractors carrying out the work, as is done in New Mexico’s oil

and gas regulations, for example.

Response 7793:

New Mexico’s oil and gas regulations include both a per-well financial assurance requirement as

well as the option for well operators to submit a blanket bond for multiple wells. The regulations

do not indicate that the amount of financial security is based on the work being carried out by

third-party contractors. Nevertheless, the Department will be requesting well operators to supply

estimated plugging and abandonment costs for wells deeper than 6,000 feet to assist in

calculating financial security requirements for deep wells. As suggested in the comment, the

amount of financial security required for deep wells will be based on the well actually being

proposed. The Department expects that in the case of multi-well pads economies of scale will

allow well operators to plug wells at a rate lower than the rate expected for single well pads.

Like other case-specific circumstances, these economies of scale will be reflected in the amount

of financial security required for deep wells.

Comment 7794:

Part 551 should be amended to provide for New York’s adopting an effective severance rate of

7.5% (similar to Texas). This will generate approximately $60 billion in tax revenues over the

next 30 years based on estimates prepared by the Pennsylvania Budget and Policy Center that

“the average Marcellus Shale well is projected to generate $16,000,000 (of energy company

revenue) over its life based on an estimated 3.8 billion cubic feet of natural gas produced from

each well at a price of $4.28 per thousand cubic feet.”

Response 7794:

Adoption of a severance tax would require legislative action and is therefore beyond the scope of

the proposed rules and the authority of the Department.

Comment 10257:

Part 551.6: It is commendable that the Department has changed this section to not place a cap on

plugging and abandoning a well.

Response 10257:

The comment is noted.

Comment 7971:

Of the 75,000 wells drilled so far in New York State, only 13,500 are still active. More than half

of the abandoned wells were never plugged or plugged improperly. The $2,000,000 liability limit

should be removed otherwise large operators have no incentive to plug their wells.

Response 7971:

The comment is noted, as the proposed rules would remove the $2 million operator cap.

83: Part 550, [Promulgation and Enforcement of Rules and Regulations] General

Comment 3681:

Part 550 is not clear on how the Department will ensure that they provide adequate staff to

enforce the regulations. It seems that the Department increasingly has less staff each year due to

budget cuts and it is believed that the Department will not have the manpower to enforce the

regulations.

Response 3681:

The Department’s staffing needs are not addressed in either existing regulation or the proposed

rules. However, the regulatory impact statement (RIS) does recognize that implementation of

the proposed rules will require the Department to incur additional costs associated with

permitting, compliance monitoring and enforcement.

Comment 3682:

Part 550 is not clear enough on how the Department will monitor and inspect the wells and

enforce the regulations. Even a small violation that goes undetected could have serious

environmental consequences.

Response 3682:

Existing Section 550.5 includes provisions that authorize the Department, its employees, agents

and representatives, to inspect any regulated facility and to access well records to determine

whether the regulations are being complied with. The proposed rules did not include any

changes to Section 550.5. However, since many of the proposed rules are based on

supplementary permit conditions proposed in the rdSGEIS for inclusion in a Department issued

Permit to Drill, the discussion in Chapter 8 concerning enforcement of the rdSGEIS is germane

to a discussion how the proposed rules will be enforced.

Comment 3683:

Part 550 needs to be in adherence with local law, which is not presently a requirement.

Response 3683:

Part 550 implements authority granted to the Department through Environmental Conservation

Law (ECL) Article 23. There is no requirement for Part 550 to adhere to local law. However,

the statutory authority for Part 550 was updated to provide clarification as to the source of the

Department’s authority.

Comment 3684:

Part 550 et seq. should be reviewed and updated annually to ensure frequent incorporation of

changes in the shale gas industry and methods.

Response 3684:

Comment noted. Please note that the Department, pursuant to SAPA, publishes a regulatory

agenda and a 5-year review of rules in the State Register.

Comment 3686:

Part 550.5(a) should be revised to include compliance with permit provisions as a reason for

making investigations or tests.

Response 3686:

The suggested change is not necessary, since paragraph 550.5(a) provides the Department with

the right to inspect to determine compliance with the rules and regulations of the Department.

This would include compliance with any permit issued pursuant to Part 552. Also, ECL Section

71-1305 already explicitly makes it a violation for any person to fail to comply with a condition

of any permit of the Department.

Comment 3689:

Part [550.6] is not clear enough regarding a penalty schedule for violations.

Response 3689:

Penalties for violations of ECL Article 23 are provided in ECL Section 71-1307. It is not

necessary to repeat the penalty amounts in regulation.

Comment 3691:

The Department should be separated from the Mineral Resources agency. This is the norm in

most states and ensures that the fox is not guarding the henhouse. If the two agencies are not

separated, then the environmental regulatory mission is simply reduced to preventing pollution

from the wells the Department issues permits for.

Response 3691:

The comment is beyond the scope of the proposed rules and suggests an action that exceeds the

Department’s authority. The Department also disagrees with the characterization that regulation

of oil, gas and solution mining is not compatible with the Department’s other environmental

protection and regulatory goals. And contrary to the assertion in the comment, it is more

common for regulation of oil and gas to be an integral part of the environmental regulatory

agency than to be a stand-alone entity, especially in the Northeast and the Appalachian Basin.

Comment 3692:

No department in New York State - including the Department, New York State Department of

Transportation, New York State Department of Health, Office of the Attorney General, and

Office of the State Comptroller - is prepared to address the regulation and taxation of shale gas

industrialization; therefore, promulgating regulations under these circumstances is irresponsible.

Response 3692:

The Department disagrees. The comprehensive regulatory scheme proposed for high-volume

hydraulic fracturing builds on the Department’s decades of experience in regulating the oil, gas

and solution mining industries.

Comment 3693:

The regulations applicable to high-volume hydraulic fracturing, including Parts 550 to 560, are

not clear and coherent as required by law. They do not provide the operators, monitors, or the

public with a clear indication of what is allowed and what is prohibited and, as is, will not

withstand legal scrutiny and challenges.

Response 3693:

The Department disagrees with the comment. The proposed rules provide a great deal of

specificity of what would be required by the regulated community. The comment does not

provide any specific examples of where clarity is sought. In response to other comments that

provided specific examples, and where the Department agreed that additional clarification was

warranted, changes in the rules were made.

Comment 3694:

In addition to the positions identified in Part 550.2, a Statewide Hydraulic Fracturing Monitoring

Committee should be appointed comprising at least one citizen representative from each of the

Department regions as well as one representative each from Riverkeeper, Sierra Club, Natural

Resources Defense Council, Environmental Defense Fund, Scenic Hudson, and/or other

environmental groups. The [chief] director of the Division of Mineral Resources should be an ex

officio member along with the regional supervisor, the United States Environmental Protection

Agency, and commissioners of the Department and the New York City Department of

Environmental Protection. The committee should meet at least monthly and advise the [chief]

director of the Division of Mineral Resources on actions to preserve and protect the resources of

New York State with special regard to the avoidance of significant impacts on the New York

City water supply system from high-volume hydraulic fracturing activities.

Response 3694:

The suggestion to form a committee is noted but is beyond the scope of the proposed rules. As

to the suggestion that the committee pay special regard to the New York City water supply

system, the proposed rules would already prohibit the siting of a well pad where high-volume

hydraulic fracturing is planned within the New York City drinking water supply watershed as

well as a 4,000 foot buffer.

Comment 4403:

In many places the definitions in the minerals regulations overlap or conflict with definitions in

the water quality (Part 750) regulations. The Department should clear up inconsistencies and

ensure that there is a full set of definitions in either Part 550 or 560. For example, the minerals

regulations do not define reserve pit as used therein, although reserve pit is defined in the

proposed water regulations (Part 750-32(44)). The proposed Part 560 definition for product

conflicts with the definition in Part 550 and neither is the same as that in Part 750.

Response 4403:

The Department agrees that the definitions proposed for Part 560 and Part 750 required

clarification. The final rules will be amended to provide the clarity and eliminate inconsistencies

as sought in the comment.

Comment 6275:

6 NYCRR 550.3(au) should be revised to read: surface casing shall mean casing installed and

cemented from the surface, through protected groundwater, to a point at least 100 feet below the

deepest protected groundwater. Protected groundwater should be defined in a way that meets

New York State long-term water needs.

Response 6275:

The Department disagrees with the proposed change to the definition of surface casing. The

existing definitions of surface casing and potable fresh water provide a clearer indication of

where surface casing should extend. The use of “protected” groundwater, as suggested in the

comment, would be vague.

Comment 7790:

Part 550.2(b): As proposed, the Director of Mineral Resources would seem to have supremacy

over environmental and public health issues related to oil, gas, and solution mining. At a

minimum, it should be expressly stated that for those concerns, responsibility and authority is

shared by other Directors within the Department or at the State Health Department.

Response 7790:

The Department disagrees both with the characterization that the Director of Mineral Resources

has supremacy over environmental and health issues and the suggestion that the DOH should be

granted authority in the proposed rules to regulate oil, gas and solution mining. The proposed

rules would implement authority granted pursuant to ECL Article 23 and Article 23 specifically

entrusts the Department, except where noted, with the authority to implement the Oil, Gas and

Solution Mining Law. DOH has its own source of authority in the Public Health Law and to the

extent activities permitted by the Department present public health issues, DOH’s authority is not

supplanted by the fact that the Department regulates the underlying activity. While DOH serves

in an advisory capacity on many issues related to high-volume hydraulic fracturing, it is not a

permitting agency for activities covered by the proposed rules.

Comment 7791:

Part 550.3(s): If refracturing is included in workover operations, it should be subject to the same

regulation as the original fracturing.

Response 7791:

An applicant proposing to perform high-volume re-fracturing during workover operations would

be required to submit the proposed Sundry Well Notice and Report form for Department review

and approval, describing the planned fracturing procedures and products, water source, proposed

site disturbance and layout, and fluid disposal plans [proposed 556.6(g)]. If the proposed re-

fracturing is high-volume, then it would be subject to the same environmental and operational

requirements as “original” high-volume hydraulic fracturing, including the requirement for

submission of the Pre-Fracturing Checklist and Certification as described by proposed

560.6(c)(22).

Comment 7792:

Part 550.1: The regulation should be amended to add an objective that emphasizes protection of

health, welfare, and the environment.

Response 7792:

The policy objectives stated in Section 550.1 mirror those in ECL Article 23 and the Department

disagrees that it is necessary to add to them, as other implementing regulations repeat the broader

policy goals of the Department to protect public health, welfare, and the environment.

Comment 8521:

Gas is not a mineral; although it may be contained within a mineral deposit such as the Marcellus

Shale. In order to hydraulically fracture a gas bearing mineral deposit, some of the shale must

first be mined (removed) for the well bore. Drilling the well bore must precede the fracturing

process. Title 9 [of Article 23 New York State Environmental Conservation Law] does not

define, address, or give authority for the mining of, or the extraction of minerals from shale gas

formations.

Response 8521:

The Department disagrees. The comment refers to Title 9 of Article 23, however, it is Title 5 of

Article 23 that directs the Department to issue a permit to drill, deepen, plug back or convert a

well. The act of drilling a well is therefore authorized under both Article 23 and the

Department’s implementing regulations.

Comment 10057:

The safe implementation of the proposed regulations (Parts 550 to 560) outlined in the rdSGEIS

this document are important, and the rdSGEIS and regulations this document will more than

adequately put a system of conditions in place to mitigate the identified concerns.

Response 10057:

The comment is noted. The Department agrees that the proposed rules will mitigate potential

environmental impacts identified in the rdSGEIS.

Comment 10885:

Since the GEIS, the Department has examined the regulatory experience in other states and

responded to the concerns of New York City and State residents. However, based on experience

in other states, there are grave concerns on whether the Department has the resources to regulate

an industry so powerful and growing in New York State.

Response 10885:

See responses to Comments 3681, 3682 and 3692.

Comment 10240:

6 NYCRR 550.2 and 750-3.2: The Department should include a definition of "downhole

operation". It is undefined in the regulation.

Response 10240:

The Department disagrees that a regulatory definition of “downhole operation” is required. It is

obvious by the nature of any proposed operation whether it would occur in the wellbore (i.e.,

“downhole”) or on the ground surface.

84: Part 552, Permits to Drill, Deepen, Plug Back or Convert Wells

Comment 3770:

Part 552: The United States Environmental Protection Agency recommends that the Department

clarify that additional requirements may apply for permits to drill, deepen, plug back, or convert

wells that involve high-volume hydraulic fracturing operations in accordance with Part 560.

Response 3770:

Since the proposed Part 560 specifically addresses high-volume hydraulic fracturing, and

proposed Section 560.1 already indicates that “each person who intends to drill, drills, or

operates a well subject to this Part shall comply with this Part’s requirements and with all

requirements contained in Parts 550 through 558 . . .” potential well operators will have

sufficient notice that an application to drill a well completed by high-volume hydraulic fracturing

requires additional information beyond that required for a well subject to only Parts 550 through

558.

Comment 3773:

The proposed revisions to Part 552.1(b) require the application for a permit to drill a well be

accompanied by a plat that shows the distance in feet from the well to the nearest plugged and

abandoned well subject to Part 552 (if same is within one mile) and the distance in feet from the

well to the nearest producing well (if same is within one mile). For directional/horizontal wells,

the United States Environmental Protection Agency suggests that the Department clarify what is

meant by distance in feet from the well (i.e., from the surface location of the well, the minimum

distance from any portion of the well, etc.).

Response 3773:

The Department’s Application for Permit to Drill, Deepen, Plug Back or Convert a Well Subject

to the Oil, Gas and Solution Mining Law (APD), already requires applicants to indicate the

proposed surface location, top of the target interval, bottom of the target interval, and bottom

hole location. Therefore, well operators are already aware of the Department’s requirements for

a well plat that accompanies an APD. Distances are measured from the surface location of the

proposed well.

Comment 3774:

Part 552.1(b): In some more densely drilled areas of the state, there may be one or more plugged

and abandoned and/or producing wells that are shallower and will not be affected by the drilling

and hydraulic fracturing of a new shale production well. However, there may also be deeper

wells nearby (but not the closest well) that, if improperly completed or plugged, may serve as a

conduit for hydraulic fracturing fluids. By only requiring the distance to the nearest plugged and

abandoned and producing wells, regardless of depth, the permit applicant is not required to

provide information on any nearby deeper wells. The United States Environmental Protection

Agency recommends that Part 552.1(b) be amended to require the distances to the nearest wells

as currently worded, but add a requirement to provide distances to the nearest plugged/producing

wells completed in the same producing horizon as the planned well is targeting.

Response 3774:

The proposed revisions to Part 560.3 would require that an applicant provide the distance to any

plugged, abandoned, or producing well, or non-producing well that is subject to Part 552 -

regardless of depth or target formation - within one mile of a proposed ECL 23 well.

Comment 3777:

Part 552.1(b) states that "if the distance between the well and the nearest well completed in the

objective pool is such that there is a possibility of violation of the spacing requirements of Parts

553.1 or 553.3, the distance between the well and the nearest well completed in the objective

pool shall be measured accurately on the ground." This statement is confusing since the proposed

revisions to this section eliminated the requirement to show on the plat the distance in feet from

the well to the nearest well completed in the same objective pool.

Response 3777:

The proposed revisions now at Part 552 would require the distance to the nearest non-producing

unplugged well (within one mile) completed in the objective pool.

Comment 3782:

For Part 552.2(c), define what is meant by the term "pursued in a diligent manner" or replace the

term with a more definitive measure such as the well must be drilled to its permitted objective or

well must be drilled and either completed or plugged and abandoned, or some other definitive

performance standard.

Response 3782:

Part 552.2(c) begins, “If the operations for which the permit is granted have not commenced and

been pursued in a diligent manner . . .” Since the rules already require an operator to commence

operations prior to expiration of the permit term, the rules already include a definitive

performance standard.

Comment 3844:

Revise Part 552.2(f) (proposed express terms numbering) such that, if the Department permits

the commencement of operations by verbal authority prior to the issuance of a formal permit, the

notifications in Part 560.5 must be followed.

Response 3844:

The comment did not specify the notifications in Section 560.5 sought to be addressed. However,

presumably the comment is referring to the notifications to the county emergency management

office that are required prior to certain events on a well pad where high-volume hydraulic

fracturing is planned. The Department understands the concern, however, verbal approval

would not relieve an applicant of the obligations in Part 560, or any other applicable regulation

of the Department.

Comment 3868:

Per Part 552, the only criterion necessary to get a drilling permit is to demonstrate that the

proposed well is at least a mile away from another well. Nothing else is taken into consideration

-- not water features, not existing land uses, not topography. This is indicative of the fact that, in

the dual role the Department has taken on, the environmental mission is secondary. This also

reinforces the need for local ordinances to keep wells out of areas where they do not belong.

Response 3868:

The commenter overlooks the fact that each APD is accompanied by an Environmental

Assessment Form, which requires applicants to describe, among a host of other facts, nearby

environmental resources. Department staff also conducts a field inspection prior to issuance of a

permit to drill to confirm information submitted in an APD. APDs submitted for wells proposed

to be completed by high-volume hydraulic fracturing would also be accompanied by the

information required in the EAF Addendum, which is Appendix 6 of the rdSGEIS. The EAF

Addendum contains an exhaustive list of information required for a complete APD.

Comment 3869:

Part 552: Require that no permits can be approved unless there are sufficient Department

personnel to inspect, at least once a week, all aspects of related drilling.

Response 3869:

See responses to Comments 3681 and 3682.

Comment 3870:

The Department should not be in charge of issuing permits because it does not have the

manpower and has a conflict of interest in its dual obligation toward protection and resource

capitalization. A separate body should be established, composed of representatives from local

governing bodies, the Department, the New York State Department of Transportation, and other

impacted organizations. This body must be fully funded and have the authority to halt all

drilling activity or permitting should funding be insufficient.

Response 3870:

The Department disagrees that a conflict of interest exists. Nevertheless, creation of a new

agency, committee or regulatory body is beyond the scope of the proposed rules and beyond the

Department’s jurisdiction. See responses to Comments 3681, 3682, 3692 and 3694.

Comment 3871:

Revise Parts 552.1(a) and (b) to require that applications and permits are required for all

activities, including deepening or plug back operations, that represent a significant change from

any such activities addressed in a related permit for the well in question.

Response 3871:

The comment suggests that a new permit should be required for any significant change in

activities specified in a permit issued for the same well. There are some circumstances where an

entirely new permit must be issued, such as instances where the surface location has been moved

more than 75 feet from the original location. In many cases, however, issuance of an entirely

new permit is not the most efficient means to review and approve of a change in the permitted

activity. For instance, in a case where a well operator requests approval to re-fracture a well, the

Department has already approved the location and issued a permit with a set of permit conditions

specific to that location. If no other part of the operation changes, it is more efficient for the

Department to approve the request to re-fracture the well based on the original set of permit

conditions. To accomplish this, the Department proposes to use a Sundry Well Notice and

Report Form. Sundry notices are used in many oil and gas producing states, and are also used on

production leases on federal land. The Sundry Form will provide an efficient means for well

operators to request approval or to notify the Department of any circumstance that deviates from

the permitted activity. Note that the operations which require a Sundry Well Notice and Report

form are now described in Part 556.

Comment 3872:

Revise Part 552.1(b) so that plats are not allowed to be certified by a civil engineer. Under New

York State Education Law Article 145, a licensed land surveyor is the only licensed professional

allowed to represent parcel boundary line locations.

Response 3872:

In 552.1(b), the Department did change “civil” engineer to “professional” engineer to be

consistent with the State Education Law.

Comment 3873:

Revise Part 552.1(c) to require that the owner or operator certify that there have been no

significant changes at the well site in question that would impact re-fracturing operations or that

might reasonably be anticipated to lead to any significant environmental impact not addressed or

mitigated in the original permit for the well.

Response 3873:

The Department disagrees that the certification proposed in the comment is necessary. Well

operators are currently required by Section 554.7 to submit a completion report detailing

operations conducted pursuant to a permit to drill. For high-volume hydraulically fractured

wells, proposed 556.2(g)(3) also provides the conditions under which the Department would

approve of a re-fracturing operation and supplementary permit conditions proposed in the

rdSGEIS would also require mandatory reporting of any non-routine incident. Coupled with the

proposed requirement to submit a Sundry Notice to notify the Department of certain events at the

well site and routine site inspections by Department staff, there are sufficient opportunities for

the well operator to communicate with the Department about any circumstance that could have

environmental implications.

Comment 3874:

Part 552.1(c) (new, additional subdivision (c)) states that, if a well is proposed for re-fracturing,

the Department will require an application be submitted at least 15 days prior to start of work.

Given the anticipated workload of drilling in the State and lack of Department staff to review

applications, it is questionable whether this is adequate time.

Response 3874:

The comment is noted. However, the Department expects 15 days to be more than adequate to

respond to a Sundry Well Notice for an existing well. Note that the Sundry Well Notice

requirements are now found in proposed 556.2(g).

Comment 3875:

Part 552.2(c) should not be changed under the proposed express terms to allow permits to expire

after two calendar years of non-operation. Permits for operations that have not commenced

should expire within 180 days, as the regulation is currently stated. Similarly, Part 552.2(d)

should not be changed under the proposed express terms to a two-calendar-year permit term and

should remain a 180-day permit term, as the regulation is currently stated.

Response 3875:

The Department disagrees. The 180-day permit term in existing regulation required Department

staff, in many instances, to issue a second permit for the same well simply because the well

operator was not able to secure a drilling rig in time to commence operations prior to expiration

of the 180-day permit term. As noted in the RIS, Department staff spends significant time and

resources to review permit application materials, conduct pre-permit site inspections, hold

hearings and issue compulsory integration orders related to permits that expire. By extending the

period of time in which an operator must commence drilling activities, the Department will avoid

the unnecessary expense associated with reviewing applications for a permit to drill, deepen,

plug back and convert a well at a location which has already been approved by the Department.

In addition, for high-volume hydraulically fractured wells, Part 560 will require well operators to

develop and implement an extensive list of plans, some of which require action prior to spudding

the well. These activities, like the testing of private water wells, would be difficult to complete

within a 180-day window.

Comment 3876:

Part 552.2(f) (proposed express terms numbering) gives the Department the ability to allow high-

volume hydraulic fracturing operations to commence without all of the safeguards involved in

the permitting process to have been fulfilled. This regulation should be removed unless the

rationale for, and circumstances under which, verbal authority may suffice in lieu of a formal

permit are clearly laid out.

Response 3876:

The provision allowing the Department to commence operations by verbal authority is an

existing provision. The Department understands the concern expressed in this comment;

however, as stated in response to Comment 3844, verbal approval would not relieve an applicant

of the obligations in Part 560, or any other applicable regulation of the Department. In addition,

the proposed revision now requires that a complete application be on file with the Department.


Comment 3877:

Delete Part 552.2(f) (proposed express terms numbering). Under no circumstances should

anyone be able to operate upon verbal authority and without a permit.

Response 3877:


Comment 3878:

Part 552.3(a) would allow for the transfer of a permit to a new owner or operator if a requesting

letter and financial security are provided. Revise the regulation to also require the new

owner’s/operator's plan for drilling or water and waste management.

Response 3878:

Part 552.3(a) is intended to address those instances, however rare, where a permitted well

operator sells or leases their working interest in a well to another operator. The proposed rules

would retain the requirement for the Department to determine if the application for re-issuance of

a permit is in order prior to approval of a new operator to take over a previously permitted

location. The Department agrees that the new operator will have to either adopt the previous

operator’s drilling and waste management plans or submit new plans consistent with Department

regulations.

Comment 3879:

Gas companies should be required to submit a Geological Survey Report and other information

for the specific site with their application before the Department issues a permit. The survey

should include all land mass formations of the site through which the drilling will go, from top

elevation to points below. The study should contain a site history of the area, containing the

locations of rivers, streams, and caverns containing water. It also should describe snow melt

runoff, natural flooding, or circumstances of heavy rains or hurricane activity to help assist

determination of runoff through sites and site pond and trench water holding systems that will be

affected. The location of area dams, reservoirs, hydroelectric power plants, mills, or any man-

made engineered systems also should be identified. The report should describe effects on

existing farmlands and crops, with data and samples of crops grown using chemical water, from

seeds to mature product. It also should address a survey for noise disturbance that would be

created by any manner of blasting, drilling, truck movement, etc.

Response 3879:

The Department disagrees that such measures are necessary. The EAF submitted with each

application for a permit to drill already requires applicants to identify existing land uses within ¼

mile of the project, nearby environmental resources such as primary or principal aquifers, critical

environmental areas and wetlands. The EAF Addendum, which would be required for wells

completed by high-volume hydraulic fracturing, also requires identification of a host of other

resources within a specified distance from the proposed well. The concerns expressed in the

comment are therefore addressed by the Department’s permitting process. As to the remainder

of the comment, the drilling of a well subject to the Oil, Gas and Solution Mining Law does not

involve blasting and potential noise impacts are addressed as a SEQRA issue in accordance with

the Department’s noise policy, DEP-00-1, Assessing and Mitigating Noise Impacts.

Comment 6287:

Industry supports the change in Part 552.2 from a 6-month to a 2-year permit term. Industry

supports the need to have a longer permit term given the uncertainties associated with the length

of time that it will take to obtain a drilling permit, which will prevent operators from scheduling

rigs and other services until a permit is granted. A longer permit term also will allow industry to

spread out development more effectively, thereby reducing the potential for short-term

cumulative impacts.

Response 6287:


Comment 6289:

Part 552.1(b): The location of wells should not only be identified "on a neat plat" as noted in the

proposed regulation, but also by Global Positioning System and tracked on a geographic

information system maintained by the Department. This tracking system should include the

condition of the well and 10-year monitoring plan.

Response 6289:

The Department’s APD currently requires the applicant to identify the longitude and latitude of

the surface location, top of target interval, bottom of target interval and the proposed bottom hole

location. This information is keyed into the Department’s oil and gas well database. It is unclear

how a GPS system could track the condition of the well, or anything other than location

information. The reference to a 10-year monitoring plan is also unclear since Part 552 does not

address monitoring of the well.

Comment 6581:

Part 552.2(e): Remove the second occurrence of the word "may" in the first sentence. It's a

typo.

Response 6581:

The typo has been corrected in the revised rule.

Comment 6585:

Part 552.3(a): Add the following sentence to the end of the section: If the operations for which

the reissued permit is granted have not commenced and been pursued in a diligent manner within

two calendar years from the date of reissuance of the permit, the reissued permit shall expire.

Response 6585:

The Department understands the concern, however, paragraph 552.2(c) would apply to any

permit to drill issued by the Department including permits issued for a location that had been

previously permitted. Therefore repeating the language in 552.3(a) is not necessary.

Comment 7795:

Part 552.1(b): The plat map should also be required to show all known seismic fractures within

one mile of the well, similar to the requirement under Part 560.3 for abandoned wells.

Response 7795:

The Department disagrees that seismic fractures should be included on a plat map. The location

information shown on the plat is intended to assist Department staff in determining whether a

proposed well meets spacing unit and other surface setbacks.

Comment 7796:

Part 552.1(c): The regulation should require pre-fracture notice and disclosure of chemicals to

be used, to both the Department and the landowner, as has been done under Wyoming's and

Colorado's regulations.

Response 7796:

The disclosure provisions for hydraulic fracturing are included in proposed Sections 560.3(c) and

560.5(h) and will apply to wells completed by high-volume hydraulic fracturing. Section 560.3

(c) addresses the information that must be disclosed to the Department at the time of permit

application, while Section 560.5(h) addresses the information that must be disclosed to both the

Department and the national chemical disclosure registry, FracFocus (www.FracFocus.org)

following well completion. As specified in the provisions, all chemical constituents of hydraulic

fracturing additives must be disclosed to the Department both at the time of application and

following well completion, and all information disclosed to the Department will be made

available to the public, except that which is sufficiently justified as trade secret in accordance

with 6 NYCRR §616.

Comment 7797:

Part 552.1(e) (proposed express terms numbering): Including a provision for good cause

suspension of the term of a permit is not necessary. If an exception is needed, the regulations

allow for a variance. Otherwise, in the absence of criteria for what constitutes good cause,

experience indicates that operators will use this regulation to "stockpile" permits and will

commence operations largely in conjunction with the market price for natural gas. Such

stockpiling should be discouraged.

Response 7797:

http://www.fracfocus.org/

It has not been the experience of Department staff that well operators stockpile permits to drill.

The time and expense of securing a permit, particularly those that will involve wells completed

by high-volume hydraulic fracturing, would discourage operators from doing so. However, there

is no regulatory basis to prevent a well operator from seeking a suspension of the permit term for

good cause. As indicated in response to Comment 3875, Department resources are wasted if

Department staff must re-review a location and re-issue a permit for a location and plan that was

previously approved.

Comment 7798:

Part 552.3(a): Reissuance of a permit to a different operator should be allowed only if that

operator is not the subject of a sanction under Sec. 750-3.20. Research across several states

indicates that operators do not pay much attention to penalties unless they interfere with their

access to producing wells. Therefore, one of the few effective enforcement mechanisms is to

prevent an operator who is not in compliance with the regulations from getting new well permits.

This subsection provides an appropriate place for such an enforcement mechanism.

Response 7798:


Comment 7799:

Part 552.1(b): The required plat should include the location and distance of private water wells

within 1,000 feet and 2,000 feet of the proposed natural gas well.

Response 7799:

The Department disagrees, as the locations and distances of private water wells within 1,000 feet

(or 2,000 feet if none are within 1,000 feet) of a gas well proposed to be completed using high-

volume hydraulic fracturing would be provided on a Department-prescribed form as part of the

EAF Addendum.

Comment 7800:

Part 552.1(a): Operations less than a true vertical depth of 500 feet should not be excluded from

these requirements.

Response 7800:

ECL 23-0305(14) expressly limits the Department’s jurisdiction under the Oil, Gas and Solution

Mining Law to geothermal, stratigraphic and brine disposal wells drilled deeper than five

hundred feet. Therefore, the change suggested in the comment is beyond the Department’s

jurisdiction.

Comment 7801:

Part 552.1(c): The Department's Sundry Well Notice and Report Form could not be found in the

public domain. Also -- the regulation should specify what information is required of the

applicant and what procedures are required of the Department prior to approval to refracture.

Response 7801:

The form would be a new form for the Department; it is not yet publically available. Instructions

included on the form will provide the necessary guidance to the regulated community on how to

obtain approval for a re-fracturing operation. However, note that the proposed rules included

paragraph 556.2(g)(4), which would apply to wells completed by high-volume hydraulic

fracturing.

Comment 7802:

Part 552.2(e): Both "on its own motion" and "good cause" should be defined or explained. This

should be modified to reduce the temporal impacts on the lessor and surrounding landowners.

Response 7802:

“On its own motion” means that the Department can decide to suspend the term of a permit. To

clarify the intent of the regulation, the word “initiative” replaced the word “motion.”

Comment 7803:

Part 552.2(f) should clarify what unusual or emergency circumstances would warrant issuance of

verbal permission to commence operations prior to the issuance of a formal permit.

Response 7803:

Part 552.2(f) has been amended to indicate that verbal permission could only be given if an

application is complete and the owner and operator are in full regulatory compliance with the

provisions of Parts 550 through 560. This provision is intended to save time in emergency

situations such as remedial operations or the drilling of an offset well during a blowout situation.

Comment 7804:

Part 552.3(a): A permit being "reissued" implies that the timeframe for completing operations

under that permit would be "reset." If true, that should not be the case; the new operator should

be obligated to comply with the timeframes of the original permit without an extension.

Response 7804:

The Department agrees. The intent of the regulation is that a new permit would be issued based

on the same terms as the permit originally issued for the same location. Since re-issuance of a

permit would not be subject to a new permit fee, the Department does not intend to spend staff

time and resources reviewing a modified application.

Comment 7805:

Part 552.1(b): The regulation should be revised to require that, before any drilling permit is

issued, a gas/drilling company must conduct a survey to identify any abandoned wells within the

proposed horizontal drillbore length and adjacent fracturing zone plus 2,500 feet and, where any

abandoned well is identified, the gas/drilling company must verify that such well has been

effectively plugged.

Response 7805:

The proposed 552.1(b) would require an applicant to identify the distance in feet to the nearest

plugged and abandoned well on the well plat submitted with an APD. The comment suggests

that all abandoned wells within a stated distance should also be included on the plat. Proposed

560.3(a)(8) would require permit applicants to identify any abandoned wells within the proposed

spacing unit and within one mile of the proposed surface location. However, the information

collected on the well plat pursuant to Part 552.2 serves a different purpose than the information

that would be collected pursuant to proposed Part 560, which is limited to wells where high-

volume hydraulic fracturing is planned. The purpose of the well plat is to assist the Department

in determining whether the proposed well meets well spacing setbacks, not to determine whether

the proposed well at target depth may communicate with previously abandoned wells. Part 552.2

also applies to all Article 23 wells and the Department disagrees that all well plats submitted to

drill an Article 23 well should reflect the same amount of information required of wells subject

to Part 560.

85: Part 553, Well Spacing

Comment 4220:

Part 553.1: The initial well spacing of 640 acres for horizontal wells can be reduced by the

Department down to 40 acres. As an oil or gas field is developed the well spacing decreases, so

the 640-acre spacing for horizontal wells is likely to decrease, meaning more well pads on

increasingly tighter spacings. This could effectively ruin surface uses. Even a spacing of 640

acres is too dense. 640 acres per well pad should be considered a least restrictive spacing that is

applied in areas with minimal environmental impacts. More restrictive standards should be

applied as necessary in forested and other areas with ecosystems that are sensitive to

fragmentation.

Response 4220:

The statewide spacing requirements found ECL Article 23, Title 5 were adopted by the

Legislature in 2005. In 2008, Title 5 was amended to provide statewide spacing options for oil

wells and for shale gas pools at any depth targeted by either vertical or horizontal wells.

Proposed Section 553.1 is intended to promulgate, almost verbatim, the statewide spacing

provisions found in the statute in order to update the concept of statewide spacing in the

regulations to conform to the statewide spacing unit sizes adopted by the Legislature in 2005.

Pursuant to ECL Article 23, Title 5, a well operator is not obligated to develop a 640 acre unit, as

suggested in the comment, since the size of the spacing unit depends, in part, on the amount of

acreage under lease.

The comment is correct that a 640 acre spacing unit for a horizontal well can be reduced by the

Department in the event that a well operator does not fully develop the entire spacing unit with

infill wells. It is also correct that limitations on the size of a spacing unit may lead to an increase

in the number of well pads constructed overall provided the acreage excluded from a reduced

spacing unit contains natural gas capable of being produced. ECL Article 23 provides the

Department with the ability to reduce the size of the spacing unit in order to protect the

correlative rights of owners in the spacing unit whose acreage may be held by production by the

first well drilled in the unit. Without this authority, which is provided in statute, a well operator

could hold acreage by production but never produce the natural gas in a timely fashion,

preventing mineral rights owners from receiving either their proportionate share of production or

a royalty. Mineral rights owners would also be prevented from either drilling their own wells or

leasing their rights to another operator. As to the concerns expressed in the comment about

fragmentation of the land, the SEQRA process provides the means to address the environmental

impacts associated with construction of additional well pads.

Comment 4222:

Part 553.1: The spacing units are too small and will result in a well density that has too much

environmental impact on communities and rural residents. Alternative spacing suggestions

include: 1) A spacing unit of 25 square miles for one multi-well pad for horizontal wells, where

the number of wells per pad is limited to six, with each less than a mile long. 2) A spacing unit of

10 square miles for single vertical wells. 3) No further infill wells should be allowed past initial

spacing. 4) Not more than one well platform in a one square mile area. 5) Not more than one

well platform in a three square mile area. 6) Only one well pad per unit.

Response 4222:

See response to Comment 4220. Statewide spacing unit sizes are provided in statute and when

the Department find that a proposed unit meets regulatory setbacks and would provide for

orderly development of the resource, a permit must be issued by the Department. If an operator

proposes a unit that does not meet the default statewide spacing options found in the statute, the

non-conforming unit hearing process is available to determine whether the proposed unit should

be approved. The comment suggests that the Department should alter the spacing options for all

horizontal and vertical wells. However, the suggested changes would conflict with the statutory

language adopted by the Legislature.

Comment 4223:

Part 553.1: Establishing a well spacing requirement of 640 acres will result in much of the

natural gas resource being unutilized or the use of numerous fill in wells that would create more

disturbance to the environment.

Response 4223:

The Department disagrees that a spacing unit size of 640 acres will result in greater surface

disturbance. In fact, the opposite is true. Improvements in drilling technology make it possible

to drill longer horizontal distances and the ability to co-locate wells means a greater amount of

the resource can be accessed on a fewer number of well pads. In addition, pursuant to ECL

Article 23, Title 5, a well operator is not obligated to develop a 640 acre unit, as suggested in the

comment.

Comment 4224:

Part 553.1(a)(6): The citation subdivision 4 of section 23-0503 of [Environmental Conservation

Law] is incorrect and should be Section 23-0503.4. This error occurs in other places as well.

Response 4224:

The comment is correct that paragraph 553.1(a)(6) contains a citation error, but not the one

indicated in the comment. Proposed paragraph 553.1(a)(6) is taken verbatim from ECL 23-

0501(1)(b)(1)(vi), which includes a cross-reference to “subdivision 4 of section 23-0503 of this

title. . .” On transcription into the proposed rule the reference to “subdivision 4 of section 23-

0503 of this title” should have been changed to “subdivision c of this section” so that the

reference pointed to the appropriate text in the regulations.

Comment 4226:

It is not clear in Part 553.1, which allows for a denser drilling pattern for vertical wells, whether

those wells would be allowed to be converted to horizontally fractured wells at a later date. If so,

this could prove to be a loophole for drillers to drill more wells than anticipated in the rdSGEIS.

This should be clarified in the regulations.

Response 4226:

Pursuant to Section 552.1, any well plugged back or deepened to a new producing horizon of a

pool requires a separate permit to drill. This includes any horizontal well drilled using the

vertical portion of an existing wellbore. With each application for a permit to drill, the

Department must evaluate and approve the proposed spacing unit to determine whether the unit

meets with the policy objectives of Article 23 and the detailed requirements provided in the

statute. The Department disagrees that a plug back or deepening of an existing vertical well with

a horizontal wellbore is a regulatory loophole, as it is commonplace and environmentally

desirable for a well operator to re-use an existing well pad, rather than drill from a new location.

As to the suggestion that well operators could drill more wells than anticipated in the 2011

revised draft SGEIS, the draft did not contain any restrictions on the number of wells that could

be drilled. Instead, the 2011 revised draft considered different rates of drilling in order to

describe the potential significant adverse environmental impacts associated with different drilling

scenarios.

Comment 4227:

Part 553.1 contains no mention of proximity to natural resources but rather references unit

boundaries. Revisions should be included to prevent unreasonable well density in or proximate to

sensitive environmental areas including but not limited to wetlands and any natural resource with

a hydraulic linkage to the New York City water supply system. Well spacing also should take

into account scaled distance from the proposed surface location of the well and the closest edge

of the proposed well pad to any primary or principal aquifer boundary, perennial or intermittent

stream, wetland, storm drain, lake, or pond within 660 feet, and any surface water body within

660 feet that is a tributary to a public drinking water supply.

Response 4227:

The comment appears to equate spacing unit boundary setbacks from setbacks for the wellbore.

Spacing unit setbacks are designed address the distance from other wells and spacing unit

boundaries, not the distance from the well to environmental resources of concern. Wellbore

setbacks and setbacks from well pads that address environmental concerns can be found in Part

553 and proposed Section 560.4.

Comment 4228:

In Part 553.1, change 330 feet to 3,000 feet or more anywhere that “330 feet” occurs.

Response 4228:

The Department disagrees that the change is necessary. However, since Section 553.1 would

promulgate language adopted by the Legislature, altering the Legislature’s regulatory language is

beyond the Department’s authority.

Comment 4229:

Part 553.1: Shale gas is not in a pool; therefore, the terminology in the regulations needs to be

changed. This should probably refer to the drilling unit.

Response 4229:

The reference to shale gas pools appears in ECL Article 23 and it is beyond the Department’s

authority to unilaterally change the words adopted by the Legislature. “Pool” is also defined in

regulation at 550.3(ah) as “an underground reservoir containing a common accumulation of oil

and gas or both. Thus each zone of a structure which is completely separated from any other

zone in the same structure is a pool.” The definition of “pool” therefore adequately describes gas

recoverable from shale formations.

Comment 4230:

Setbacks and measured distances addressed by Part 553 should be required to be measured with

respect to the edge of the well pad, and not the well bore, in order to be consistent with the

rdSGEIS and other portions of the regulations.

Response 4230:

In some cases it is appropriate to impose a setback from the wellbore and in other cases a setback

should be measured from the well pad. Setbacks included in proposed Section 560.4 are

measured from the well pad because the setback is intended to address multi-well pads where

high-volume hydraulic fracturing is planned. The Department expects most high-volume

hydraulically fractured wells will be sited on multi-well pads. Part 553 applies to all ECL

Article 23 wells.

Comment 4231:

Revise Part 553.2 such that setbacks from the edge of the well pad are increased. Suggestions

include: 500 feet from homes and public buildings, 1,000 feet from homes whose owners did not

sign a lease, 1,000 feet from schools, 2,000 feet from any water body, and 5,000 feet from

residential and municipal well water sources.

Response 4231:

See response to Comment 4230. The revised proposed rule does, in Part 560.4, include an

increase in the setback for inhabited private dwellings and places of assembly to 500 feet for

wells where high-volume hydraulic fracturing is planned.

Comment 4232:

Part 553.3(a): The Department should not allow any spacing units for shale gas in which people

have been compulsorily integrated. The original reason for forcing people in was so gas would

not be extracted from under them without their being compensated. But since you cannot extract

shale gas without trespassing under people’s property, the reason for forced pooling does not

exist and should be removed.

Response 4232:

The commenter appears to misunderstand the concepts of well spacing and compulsory

integration. Spacing units, created by issuance of a permit to drill or by order of the Department,

establish the acreage assigned to a given well. Once the spacing unit is established, any unleased

mineral rights in the unit are addressed through the compulsory integration process. Therefore,

the suggestion in the comment that the Department should not allow spacing units in which

people have been compulsorily integrated has the order reversed. It is also incorrect to equate

gas production in a forced pooled unit with a trespass. A compulsory integration order, pursuant

to ECL 23-0901(3)(c)(1)(ii)(f), specifies that all well operations conducted on any portion of

spacing unit shall be deemed for all purposes the conduct of such operations upon each

separately owned track. Therefore, the drilling of a well on any portion of an integrated spacing

unit is permitted by statute. Nevertheless, as the proposed paragraph 553.3(a) is a verbatim

recitation of ECL 23-0503(2), no changes were made as a result of the comment.

Comment 4234:

Parts 553.3 and 553.4: Exceptions, modifications, or variances to the statewide spacing

requirements should not be allowed under any circumstances. The public has a right to know the

maximum well density they will be subjected to and not have it changed in the future at the

discretion of the Department or others.

Response 4234:

The commenter should note that the statewide spacing unit sizes listed in subdivisions 553.1(a)

and (b) are not among the list of spacing options where a variance is available in 553.3 and

553.4. Since the default statewide spacing units are specified in the statute, it is not within the

Department’s discretion to issue variances from the spacing unit sizes. ECL 23-0503(3) provides

the applicant with the means to propose a non-conforming unit that does not meet statewide

spacing requirements. The Department must first conduct a technical review to determine if

issuance of the well permit meets the policy objectives of Title 3 of Article 23.

Comment 4235:

Parts 553.3(e) and 553.4: If exceptions, modifications, or variances are allowed, all parties in the

spacing unit, as well as local government, should be required to be notified in writing of any

variance request and given at least two months to comment on it after they have been notified.

Putting it in the environmental notice bulletin is akin to hiding it and circumvents public

comment.

Response 4235:

The Department disagrees that publishing a public comment period in the Environmental Notice

Bulleting is akin to hiding the public comment period. Proposed subdivision 553.4(a) already

specifies that the owner or operator must also provide notice of the public comment period by

publication. The Department disagrees with the suggestion that at least two months should be

given to affected individuals and local government. The variances that would be allowed under

proposed subdivision 553.4(a) are limited to wells exempt from statewide spacing and the

wellbore setbacks provided in Section 553.2.

Comment 4236:

Part 553.3(e) (proposed express terms new subdivision (e)): Define the term "reasonable

opportunity" and the process of ensuring that affected persons are notified if a hearing is not

involved.

Response 4236:

The language proposed for subdivision 553.3(e) is identical to language included in ECL 23-

0305(6). The length of the comment period needed for modification of a previously established

spacing unit will depend on the circumstances, however, in the past the Department has provided

affected persons with 30 days to comment on a proposed spacing order.

Comment 4238:

Part 553.4(a) should be revised. The current wording appears to take decision-making authority

away from the Department and forces it to issue a permit if the public does not comment. The

Department should be allowed to raise its own issues and be required to make a finding of no

significant impact even in the absence of any public comments or comments that do not raise

substantive and significant issues.

Response 4238:

The Department understands the concern since the words “Where in its opinion there exists good

and sufficient reason to permit an exception to the well spacing provision . . .” will be deleted.

However, the proposed rule will now begin, “The department may permit reasonable well

location variances. . .” Therefore, the granting of a variance will require the exercise of

discretion and issuance of a variance will not be mandatory.

Comment 4239:

For Part 553.4, the terms for variances to well spacing and the notification requirements for

proposed variances are not clearly specified. Well spacing variances should not be granted until

all impacts, including effects on air quality, noise in the area, roads, and the possible impact of

the structure of neighboring gas well casings, have been evaluated.

Response 4239:

The specific purpose of the public comment period specified in Section 553.4 is to elicit

comments on the request for a variance from either the unit setbacks for wells exempt from ECL

23-0501 or the wellbore setbacks provided in Section 553.2. This process is separate and distinct

from the technical and environmental review of the APD.

Comment 6308:

New York State has created a detailed statutory scheme for spacing and compulsory integration

to promote the greater recovery of the resource and protect correlative rights. See Environmental

Conservation Law (ECL) Article 23, Title 5. ECL 23-0503(2) authorizes the issuance of permits

to drill wells if a proposed spacing unit conforms to statewide spacing and is of approximately

uniform shape with other spacing units within the same field or pool, and abuts other spacing

units in the same pool, unless sufficient distance remained between units for another unit be

developed. For the more uniform plays like the Marcellus and the Utica, this is likely to require

relatively uniform rectangular-shaped abutting units in order to avoid gaps in the development of

the resource. The Part 553.1(a)(6) requirement that all horizontal wells be drilled from the

common well pad within three years of the date the first well in the unit commences drilling may

be unrealistic. The same is true for the 553.1(c) requirement that infill wells deemed necessary

must be drilled within three years from the date the first well in the unit commences drilling.

Industry recommends that Part 553.1(c) be more flexible to accommodate potential legislative

changes and, therefore, should be amended to read as follows: In a spacing unit established

pursuant to paragraph (6) of subdivision (e) of this section, infill wells shall be deemed necessary

to satisfy the policy objectives of Part 550 of this Title.

Response 6308:

The Department agrees with this comment and the proposed regulations have been revised

accordingly.

Comment 6309:

Industry recommends that should the Department decide not to allow waivers from the final

prohibitions and spacing requirements [listed in 6 NYCRR Part 553], the variance provisions of

553.4(a) should be expanded to include variances from certain of these requirements and

prohibitions and other substantive requirements where waivers are not allowed.

Response 6309:

As proposed, Section 553.4 would provide the means to obtain a variance from the spacing

requirements listed in Part 553 except in the case of statewide spacing units established by ECL

23-0501(1)(b). Pursuant to ECL 23-0503(3), any proposed unit that does not meet statewide

spacing requirements is subject to the similar, but not identical, non-conforming unit process

provided in the statute.

Comment 6605:

Part 553.1(c) should be revised to state: The department may issue permits to drill infill wells

on a reasonably uniform pattern within the spacing unit after an integration order has been

issued, if required, and only if it determines that drilling infill wells is necessary to satisfy the

policy objectives of Part 550 of this Title. The distances from the unit boundaries set forth in this

section shall apply to any infill wells. For purposes of this section, new lateral wellbores drilled

from the original wellbore in the unit are not considered infill wells if they are drilled prior to the

first product sales from the original surface location. In a spacing unit established pursuant to

paragraph (6) of subdivision (e) of this section, infill wells shall be deemed necessary to satisfy

the policy objectives of Part 550 of this Title.

Response 6605:


Comment 6606:

Part 553.3(c) (proposed express terms numbering): change the word "promulgated" to "issued."

Response 6606:

The Department agrees with the suggested change and the final rule was amended to clarify the

intent of the regulation. “Promulgated” was used in subdivision 553.3(c) since it appeared in

existing subdivision 553.3(b), which will be the new 553.3(d). For consistency, both instances

of the word have been changed in the revised proposed rule. The Department also changed

“Title” to “Part” for clarity.

Comment 6607:

Part 553.4(a): Revise the first sentence to: [Where in its opinion there exists good and sufficient

reason to permit an exception to the well spacing provision of section[s] 553.1, 553.2 and 553.3

of this Part, t] T he department may permit reasonable well location [exception] variances to the

well spacing provisions of subdivisions (d) and (e) of section 553.1, sections 553.2 and 553.3 of

this Part, and the requirements of Part 560 (to the extent that waivers are not available to the

operator), in order to [which will] protect correlative rights and prevent waste."

Response 6607:

The Department agrees that waivers to Part 560 should be available under specific

circumstances, and the regulations have been updated accordingly.

Comment 6608:

Part 553.4(b): Add the following sentence to the end of the section: "Any such hearing shall be

scheduled as expeditiously as possible consistent with the requirements of the ECL."

Response 6608:

ECL 23-0501(3) obligates the Department to take actions as expeditiously as possible, however

this subdivision doesn’t expressly apply to hearings on a spacing variance request since it is

limited to titles 7 and 9 of ECL Article 23. Nevertheless, the Department endeavors to schedule

all hearings required by ECL Article 23 as soon as possible.

Comment 7806:

Part 553.2: In light of the increased setbacks contained in portions of these proposed rules, this

section needs to be amended to reflect those changes. The minimum setback from any stream,

river, other body of water, or private water well needs to be at least 3,000 feet. Furthermore, the

setbacks listed here for public buildings and dwellings do not meet the minimum socially

necessary distance to prevent conflict between appropriate surface uses and production of gas or

oil. Other states have larger setbacks that could be looked to for guidance as to the appropriate

setback distance; for example, California's recommendation for industrial facilities is a quarter-

mile setback from public buildings in order to maintain air quality.

Response 7806:

Part 560 proposes additional setbacks for wells completed by high-volume hydraulic fracturing.

Comment 7807:

Part 553.3(e) (proposed express terms numbering): In light of the addition of new language

referring to notice and comment for "affected persons," there needs to be a definition of who an

"affected person" is. The controversy around downspacing in other states shows that this zone of

who is affected must include landowners and local governments, at a minimum. Also, the

regulation needs to define what a "reasonable opportunity to comment" is; that is, what kind of

notice is necessary and how it should be provided.

Response 7807:

A modification to spacing unit boundaries would occur after a permit to drill is issued, so unless

local government controls mineral rights in the spacing unit, the Department disagrees that local

governments should be considered affected persons. As to the portion of the comment seeking a

definition of a “reasonable opportunity to comment”, see response to Comment 4326.

Comment 7808:

Part 553.2: The regulation should be revised to establish a minimum setback distance of not less

than 300 feet, measured on the surface but extending subsurface to preserve the fee simple

ownership of all subsurface rights, for all drilling and all ancillary activities, from the boundary

lines of all parcels containing a residential structure, a school, or any public building.

Response 7808:

The proposed regulations did not include a change to Section 553.2 and the Department

disagrees that the change suggested in the comment is necessary. If a surface owner also

controls the mineral rights to their land, they can simply protect their real property interests by

not signing a lease.

Comment 7809:

Part 553.1(c): Parts 553.1(a)(6) and (7) document spacing requirements based on the

commitment of operators to drill/not drill infill wells. The regulations should clarify how these

requirements align timing-wise and procedurally with the requirements of Part 553.1(c). For

example, how would these requirements be managed in gas fields with existing wells, such as

Chautauqua County?

Response 7809:

Subdivision 553.1(c) indicates that infill wells are deemed necessary for spacing units created

pursuant to 553.1(a)(6). The number of infill wells needed will vary widely since the spacing

unit size could be any size up to 640 acres +/- 10% for a horizontal well. ECL Article 23

requires well operators to drill all infill wells in a spacing unit created for a horizontal shale well

within three years of the date the first well in the unit commences drilling. The concern

expressed about existing gas fields in Chautauqua County is unclear, as the existing statutory 3-

year infill requirement applies only to shale wells.

Comment 10942:

The Department's Proposed Regulations modify existing drilling regulations in ways that make

drilling operations subject to even less public and regulatory oversight. For example, applications

for well spacing variances formerly automatically required the Department to schedule a public

hearing on the variance; under the Proposed Regulations, the default is for the Department to

grant the variance request, and a public hearing would only be scheduled if, after a 15 day

comment period, the Department determined that substantive and significant issues were raised.

The Departments Proposed Regulations severely limit the role of public participation and also

limit Department authority to review major drilling operation decisions before they are made.

Response 10942:

The only difference between the existing and proposed regulations is that a public comment

period will provide an opportunity for the Department to receive comments on the application

before scheduling a hearing and Department staff will be provided an opportunity to determine

whether a hearing is even necessary. Holding a public comment period prior to scheduling a

hearing would also make the process of reviewing variance requests consistent with the public

notice and hearing requirements found in other parts of ECL Article 23, such as 23-0503(3) and

23-0503(6).

86: Part 554, Drilling Practices and Reports

Comment 3786:

Part 554.1(c)(1) should be revised to state that contingency plans must be submitted to the

Department for the disposal of wastewater if the primary method of fluid disposal is a publicly-

owned treatment works (POTW), to be consistent with Section 1.7.9 of the rdSGEIS.

Response 3786:

The Department agrees that a contingency plan should be required for every well that is high-

volume hydraulically fractured. However, Part 554 applies to all wells regulated under ECL

Article 23 and it would be unreasonable for an operator of a geothermal well, for example, to

have to prepare a contingency plan for the minimal amount of fluids that may require disposal

following completion of drilling operations. The Department’s discretion is necessary and the

proposed rules would clarify that failure to obtain approval of an operator’s proposed plan would

serve as a basis for the Department to require preparation of a contingency plan. See also

Response to Comment 3441 in Category 90: Part 750, State Pollutant Discharge Elimination

System (SPDES) Permits including permits for High Volume Hydraulic Fracturing

Operations. .

Comment 3787:

Parts 554.1(c)(2) and (3) should be modified to prohibit the on-site storage of brine and salt

water and require that all drilling mud reserve pits be lined to reflect current Department on-site

fluid storage requirements.

Response 3787:

The change suggested in the comment would remove an operator’s ability to maintain fluid

storage for recycling purposes. Additionally, existing regulation at Part 554.2 states that the

standard for all pits, regardless of construction, is watertight as to prevent escape of any fluids.

Comment 3788:

Part 554.4(c) seems to allow operators to not use blowout equipment in areas where subsurface

formations and pressures have been reasonably well established by prior drilling practice if it is

in accordance with established local practice. Yet Section 5.2.1 of the rdSGEIS states that Part

554.4 requires blowout equipment to be maintained and in proper working order during

operations with no such caveat mentioned. Part 554.4(c) should state that blowout equipment is

always required.

Response 3788:

The Department did not propose any revisions to Part 554.4. Part 554 applies to all wells

regulated under ECL Article 23 and it would be unreasonable and/or impractical for an operator

of a geothermal, monitoring or shallow oil well where subsurface pressures have been well

established to require the installation of blowout prevention equipment. Proposed Part 560

require the use of blowout prevention equipment in every instance for high-volume hydraulically

fractured wells.

Comment 4233:

Parts 554.1(a) and (b) are completely inadequate and must be set out in detail and the public

allowed to comment on them.

Response 4233:

The Department disagrees. A general statement prohibiting pollution by wells addresses a broad

range of potential issues and is an effective enforcement tool when a specific activity is not

addressed in the regulations.

Comment 4319:

The Drilling and Production Waste Tracking Form, as required by Part 554.1 (and addressed in

rdSGEIS Appendix 10 item 53), with original signatures should be retained indefinitely by the

Department. This might become valuable information if any improprieties are discovered in the

future.

Response 4319:

The Department maintains records in accordance with a records retention policy and will take

such comments under consideration when setting the timeframe for disposal of Department

records.

Comment 4592:

Part 554.1 states that a plan for the disposal of brine, salt water, or other polluting fluids be

prepared and submitted to the NYSDEC for approval. However, drilling muds are not expressly

mentioned or included in the assessment of polluting fluids. Drilling mud can contain water,

bentonite, polymers, caustic soda, barite, and oil. Considering the negative impact some of these

chemicals can have on water quality and aquatic life if released into the environment, the United

States Fish and Wildlife Service recommends that drilling muds be included in any plans that

cover proper containment, transportation, treatment, and disposal, and that the proposed

regulations be revised accordingly.

Response 4592:

The proposed rules contained a bracket around the sentence in existing paragraph 554.1(c)(1)

which read: “For purposes of this subdivision, drilling muds are not considered to be polluting

fluids”. The brackets indicated the Department’s intent to delete this sentence to clarify that the

fluid disposal plan must address the disposition or disposal of drilling muds. The comment’s

recommendation was therefore part of the proposed rulemaking.

Comment 4594:

Regarding Part 554.1: we agree with the proposed revisions to this part including the

requirement for the operator to submit and receive approval for a plan for the environmentally

safe and proper disposal or beneficial re-use of drill cuttings on-site or off-site before a permit is

issued.

Response 4594:


Comment 4595:

The requirements in Part 554.1(c)(1) are too vague for the importance of this topic. While

requiring that the well permit applicant furnish a plan to show how fracturing waste will be

disposed of, there is no objective standard proposed for "environmentally safe and proper

ultimate disposal of such fluids." In most states, that would mean put into a disposal well, but

there are no disposal wells in New York State. The proposed regulation refers to the "sensitivity

of the surrounding environment to the polluting fluids," implying that ultimate disposal could

consist of dumping the fracturing waste on-site. Because in hydraulic fracturing the produced

water is stored in open pools prior to being disposed of, this regulation should read -- the

operator must submit and receive approval for a plan for the environmentally safe and proper

immediate storage and ultimate disposal of such fluids. The regulation also does not specify

allowable levels and limits for the different chemicals that will be in the wastewater. This vague

language underscores the concern that there is no economically and environmentally responsible

way to get rid of the billions of gallons of wastewater that would be produced by shale gas

industrialization.

Response 4595:

The Department disagrees that the 554.1(c)(1) is either vague or underscores that no responsible

disposal options are available to well operators. Paragraph 554.1(c)(1) simply outlines some of

the considerations that may be relied on by the Department to approve a fluid disposal plan. The

Department must also correct the statement in the comment that “produced water is stored in

open pools.” For several years now, the Department’s proposed supplementary permit

conditions for wells completed by high-volume hydraulic fracturing have proposed that flowback

be directed to tanks. The storage of production brine in on-site pits has also been prohibited in

New York since 1984.

Comment 4596:

Part 554.1(c) should be revised to also address the following: Contaminated filter sludges from

radium removal from flowback water will require proper disposal. The Department should also

require that the aquifer be tested for concentrations of hydrocarbons, arsenic, mercury, total

dissolved solids, and radium before well drilling commences so that a baseline of background

concentrations is known and the Department will know whether gas well drilling and production

have contaminated an aquifer.

Response 4596:

The Department recognizes that wastes produced from the treatment of production brine must be

addressed since the treatment of production brine may result in processed and concentrated

naturally occurring radioactive material (NORM). However, filter sludges created by treatment

of production brine are not generated at the well site, but at an off-site facility. The disposal of

processed and concentrated NORM is regulated under 6 NYCRR Part 380, rather than Part 554.

The Department also disagrees that the rules which apply to all ECL Article 23 wells should be

amended to require baseline testing of aquifers. The proposed rules in Part 560 would prohibit

the siting of high-volume hydraulically fractured wells in some aquifers and a stated buffer, and

would require baseline testing of private water wells.

Comment 4597:

For Part 554.1(c)(1), drilling muds should be considered polluting fluids, and perhaps even

hazardous waste, and should not be exempt from the requirement to be disposed of in an

environmentally safe and proper way.

Response 4597:


Comment 4598:

Drill cuttings are addressed in Part 554.1(c)(4), where it states that an operator must receive

approval of a safe and proper disposal plan or beneficial re-use plan for the material. The United

States Fish and Wildlife Service has concerns about approving beneficial re-use of cuttings that

may contain elevated levels of naturally occurring radioactive material (NORM) without prior

proper testing and reporting. Prior to the removal or disposal of drill cuttings, the Department

should require adequate testing for NORM and report the results to the public, including adjacent

landowners. The Department Mining Database may be an appropriate repository.

Response 4598:

The comment is noted. The Department evaluated the potential for NORM to exist in drill

cuttings and found that it is processing activities that have the potential to accumulate NORM

that requires regulatory oversight. The approval process for beneficial use of a waste material is

addressed by 6 NYCRR Part 360 and any application for a beneficial use determination would

need to contain analytical data supporting the request.

Comment 4599:

The word "unreasonably" in Part 554.5(a) is too vague and needs to be defined. As well, the

permit should be modified if major changes are desired.

Response 4599:

The Department disagrees that the word “unreasonably” is too vague and needs to be defined.

Staff will review the “as drilled” wellbore to determine that well spacing requirements for the

unit have been met. The Department will require modification of the unit or possibly order the

well plugged should the well be drilled in violation of the well spacing requirements.

Comment 4600:

For Part 554.7(d): A Department inspector should be on hand to observe the sample drill

cuttings collected in every case.

Response 4600:

The Department disagrees that staff should have to witness the collection of drill cuttings.

Comment 4602:

For Part 554.7(e), no information from the completion report and well log and drill cutting

samples should be considered confidential. The information also should be made available on the

Department website within two days.

Response 4602:

ECL 23-0313 specifically addresses the confidentiality of information related to regulated wells

and the Department implements this aspect of the Oil, Gas & Solution Mining Law accordingly.

A change in the accessibility of well records by the public would require legislative action.

Comment 5798:

Secondary containment requirements for fuel tanks should extend to all hydrocarbon drilling and

high-volume hydraulic fracturing operations in New York State. The requirements should not be

limited to shale gas drilling and high-volume hydraulic fracturing operations. These

recommendations should be captured in 6 NYCRR 554.

Response 5798:

Proposed Part 560.6(b)(1)(i) would require secondary containment for fueling tanks for high-

volume hydraulic fracture operations in New York.

Comment 6343:

Section 554.5(a) should be clarified as to what unreasonably means where the bottom hole

assembly is lost in the hole and a sidetrack is needed. Industry recommends that the requirement

for the Department to approve a proposed modification to the well's path and/or bottom hole

location be modified so as to permit verbal approval in order to facilitate operations. Specifically,

Industry recommends that the following sentence be added to proposed amendment to 554.5(a):

For good cause shown, verbal approval may be granted in response to emergency or unforeseen

circumstances.

Response 6343:

See Response to Comment 4599. The Department disagrees that the proposed language is

necessary. Proposed 556.2(g) would provide the requested authority for verbal approval of

operations that normally require pre-approval based on a Sundry Well Notice and Report form

filed by the operator. The Department will consider the operator’s justification for these

modifications prior to approval and may require additional information to determine the need for

modification.

Comment 6361:

A recommendation for this section is to streamline surface casing regulations by amending the

regulations to include requirements contained in the 2011 rdSGEIS and standard stipulations.

The Department has included some, but not all, of these requirements in the regulations.

However, there are a number of inconsistencies between the permit conditions and the

regulations. Additionally, there are a number of new surface casing requirements proposed for

high-volume hydraulic fracture wells that are standard industry best practices for all oil and gas

wells. These requirements should be included in Part 554 (drilling practices for all oil and gas

wells) and not contained just in Part 560 (drilling practices for high-volume hydraulic fracture

wells). Nor should these requirements be found just in permit conditions (permit conditions

should be reserved for site- and project-specific requirements). Part 554.1(d) should be revised

to require the surface casing setting depth to be at least 100 feet below protected groundwater for

all wells, or the Department should provide a technical justification for reducing the setting depth

to 75 feet for some wells. Parts 554.1(d) and 554.4(a) should be combined or at least be

consistent to require the surface casing setting depth to be at least 100 feet below protected

groundwater. The regulations should require the protected groundwater depth to be estimated in

the drilling application to aid in well construction design, and require the protected water depth

to be verified with a resistivity log or other sampling method during drilling. If the protected

water depth is deeper than estimated, an additional string of intermediate casing should be

required. Additionally, the regulations need to be clear on whether their purpose is to protect

potable fresh water only or a broader definition of protected groundwater, which would result in

surface casing being set deeper. Part 554.4(b) should be revised to be consistent with the

proposed rdSGEIS Appendix 8 and 9 permit conditions and Appendix 10 best practices for high-

volume hydraulic fracturing. If cable tool drilling is anticipated for New York State, Part 554.3

should be revised to require these wells be constructed to the same quality standards as wells

drilled with rotary drilling equipment. Part 554.1(c)(1) should be revised to require a more

robust waste management planning and oversight process, including detailed instructions on

collection, testing, transportation, treatment, and disposal of waste.

Response 6361:

Part 554 applies to all wells regulated under ECL Article 23 and it would be unreasonable and/or

impractical for an operator of a geothermal, monitoring or shallow oil well to comply with the

same requirements placed on high-volume hydraulically fractured wells. The Department

currently has a 75-foot depth of setting surface casing below the deepest fresh water zone

encountered or 75 feet into competent bedrock, whichever is deeper. The casing depths proposed

in the drilling application must take the depth to base of fresh water into account. Per existing

regulations, the surface casing setting depth requirement is below potable fresh water. The waste

disposal plan will be reviewed by Department staff to determine its adequacy and completeness.

Comment 6362:

The recommendations listed in the Surface Casing Analysis Table (Appendix A to the Harvey

Consulting LLC report) should be considered for the rdSGEIS and Part 554. The Harvey

Consulting LLC report addresses the following, for which their specific recommendations should

be incorporated: Surface Casing Setting Depth, Protected Water Depth Verification, Cement

Sheath Width, Amount of Cement in Annulus, Shallow Gas Hazards, Excess Cement

Requirements, Cement Type, Cement Mix Water Temperature and pH Monitoring, Lost

Circulation Control, Spacer Fluids, Hole Conditioning, Cement Installation and Pump Rate,

Rotation and Reciprocation, Centralizers, Casing Quality, Casing Thread Compound, Drilling

Mud, Cement Setting Time, New York State Inspectors, Cement Quality Assurance/Quality

Control, Formation Integrity Test, Blowout Preventer Installation, Record Keeping, Additional

Casing or Repair, and Pressure Testing.

Response 6362:

Many of the recommendations listed are required and implemented through DEC’s guidelines

and/or permit conditions. Note that the Harvey report was focused on the SGEIS, which relates

to high-volume hydraulic fracturing. Such operations are addressed by requirements proposed in

Part 560.

Comment 6367:

Part 554.1(b) should be amended to add that pollution of the air is also prohibited.

Response 6367:

A general statement prohibiting pollution by wells addresses a broad range of potential issues

and is an effective enforcement tool when a specific activity is not addressed in the regulations.

Specific air pollution issues are addressed by the Division of Air Resources’ regulations.

Comment 6368:

Part 554.1(c)(1) should be modified from its current statement of "sufficient quantities to be

deleterious to the surrounding environment" to "in more than de minimis quantities," as the

current language is so vague as to be unenforceable. We agree with the deletion of the sentence

related to drilling muds. We also believe that the Department should explicitly take into account

the seismic history of the area before approving a plan for disposal of fluids.

Response 6368:

The statement “sufficient quantities to be deleterious to the environment” has been deleted. As

to the comment that the Department should take into account the seismic history of the area

before approving of a fluid disposal plan, a consideration of the area’s seismic history would

only be relevant in cases where disposal is through use of a disposal well. In those instances, a

SPDES permit would be necessary and the review of the injection well would be guided by

applicable SPDES regulations, as well as any requirements imposed by the EPA pursuant to the

Safe Water Drinking Act.

Comment 6370:

Part 554.2 should be amended to require a minimum of 48 hours notice to the Department before

drilling or fracturing operations commence, which would allow for observation of such

operations by Department staff.

Response 6370:

Existing Part 554.2 has been amended to require at least 24 hours notice prior to the start of

drilling operations. Proposed 560.6(c)(22) requires submittal to the Department of the pre-

fracturing checklist at least 3 days before the proposed high-volume hydraulic fracturing

operations.

Comment 6371:

Part 554.4(a) should be amended to specify that cementing of the production casing be from a

minimum of 100 feet below the deepest potable fresh water to the surface.

Response 6371:

The Department did not propose any revisions to Part 554.4. The current requirement of setting

surface casing 75feet below the deepest fresh water zone for all wells provides adequate

protection.

Comment 6372:

Part 554.5(d): The required information for horizontal or directional wells under this subsection

must also include the names and contact information for landowners, the location of any water

wells within one mile of the down hole location, baseline monitoring data for each of those water

wells, and documentation of delivery of that baseline data to each water well owner.

Response 6372:

Part 554 applies to all wells regulated under ECL Article 23 and it would be unreasonable and/or

impractical for an operator of a non-vertical geothermal, monitoring or solution mining well to

comply with the same requirements placed on high-volume hydraulically fractured wells. The

Department disagrees that the proposed informational amendments should be listed in the

controlled directional drilling section of the regulations.

Comment 6373:

Part 554.5(e): The plan view should include any water wells that are present.

Response 6373:

The plan view map in 554.5(e) specifically requires information regarding the orientation of the

wellbore and its subsurface path with respect to drilling to the target formation. It is not the

purpose of this map to evaluate the location of nearby water wells, therefore the proposed

revision is not necessary in this section of the regulations.

Comment 6374:

Part 554.7(a) should be amended to require that within 30 days, an operator must also post, on a

publicly accessible website, a list of all chemicals used during drilling and fracturing.

Response 6374:

The revisions of Part 554.7(a) specifically refer to the filing of a completion report or interim

completion report with the Department. The proposed amendment is not relevant to the filing of

a completion report and is therefore not necessary in this section of the regulations.

Comment 7810:

Part 554.(c)(1) should clarify the circumstances under which the discharge/disposal of produced

fluids might not require a permit.

Response 7810:

The Department requires that produced fluids be disposed of properly. The Department does not

believe it is necessary to list in Part 554 circumstances under which the discharge/disposal might

not require a permit. A permit will always be required if the proposed disposal method requires

one (e.g., underground injection at a disposal well, discharge via a wastewater treatment plant,

etc.) This determination will be made upon review of the fluid disposal plan.

Comment 7811:

Part 554.7(a): The Well Drilling and Completion Report form could not be found in the public

domain. Are these forms still in development?

Response 7811:

The Well Drilling and Completion Report form is in the public domain at

http://www.dec.ny.gov/energy/4761.html.

Comment 7812:

Part 554.7(e): Drill cutting samples could be useful to better understand chemical properties and

potential health concerns related to drilling. This provision should be modified to allow for their

examination by the State Health Department (or other suitable entity).

http://www.dec.ny.gov/energy/4761.html

Response 7812:

Drill cuttings are available to other departments, including State Health Department, agencies

and offices of state governments according to the provisions of ECL 23-0313.

Comment 7813:

Part 554.1(c)(1) will require a fluid disposal plan to be approved by the Department prior to well

permit issuance for "any operation in which the probability exists that brine, salt water or other

polluting fluids will be produced or obtained during drilling operations in sufficient quantities to

be deleterious to the surrounding environment." To fulfill this obligation, the Environmental

Assessment Form Addendum will require information about waste fluids disposition, including:

planned transportation off-site; planned disposition; and identification and permit numbers for

proposed treatment facility or disposal well in New York. Industry suggests that this level of

detail and duration may be unduly burdensome, create difficulties in responding to unforeseen

issues, and inhibit the growth of a valid water treatment business to the extent that it effectively

locks operators into a long-term arrangement that may be more costly in terms of dollars and

environmental impacts. Accordingly, Industry suggests that the Department include allowances

for operational flexibility in the Fluids Disposal Plan and limit the duration of the planning

commitment to no more than 5 years.

Response 7813:

The fluid disposal plan discussed in 554.1(c)(1) and the EAF Addendum does not lock operators

into a long-term arrangement but is flexible so that operators may amend the plan should other

disposal options become available. The plan is necessary at the time of permitting to ensure that

operators have an approved disposal site for its drilling and production related wastes.

Comment 10296:

There are a number of new intermediate casing requirements proposed for high-volume

hydraulic fracture wells that are standard industry best practices for oil and gas wells. Those

requirements should be included in Part 554 and not just covered in the new Part 560.

Response 10296:

Part 554 applies to all wells regulated under ECL Article 23 and it would be unreasonable for an

operator of a geothermal, monitoring or shallow oil well, for example, to install intermediate

casing when it is not required or necessary. Department staff reviews each drilling permit’s

casing proposal to determine if the program requires the installation of one or more intermediate

casing strings.

Comment 10943:

The Department's Proposed Regulations modify existing drilling regulations in ways that make

drilling operations subject to even less public and regulatory oversight. Under the previous

regulatory program, a written permit application was required to deviate a vertical well to drill

directionally and the Departments receipt of such an application would trigger a compulsory ten-

day waiting period for objections; if objections were received or if the Department was not in

accord with the deviation, a public hearing would be scheduled to determine whether directional

drilling should take place. Under the Proposed Regulations, no provision for review or public

hearing is made; operators must simply notify the Department of their intention to deviate a

vertical well and provide a follow-up angular deviation and directional survey within thirty days

of doing so. With respect to spacing unit variance applications and applications to directionally

drill, The Department’s Proposed Regulations severely limit the role of public participation and

also limit Department authority to review major drilling operation decisions before they are

made.

Response 10943:

The Department respectfully disagrees with the commenter that the modifications to Part 554.5

make drilling operations subject to less public and regulatory oversight. The 10 day waiting

period and hearing listed in the prior version of this section, when taken in context, allow offset

operators to voice their objection to the deviated well. The Department will require modification

of the unit or possibly order the well plugged should any well be drilled in violation of the well

spacing requirements found in ECL 23-0501. Any drilling application received by DEC that

includes a spacing unit variance results in the publication of the proposed variance in the ENB

and a call for public comments. Public participation in the spacing unit variance process has not

been diminished. The Department has authority to review major drilling operation decisions

before they are put into effect.

87: Part 555, Plugging and Abandonment

Comment 3791:

Many of the older wells, particularly enhanced recovery injection wells, are constructed with

tubing on a packer with cement on the packer. The requirements under Part 555.5(a)(1) ignore

the plugging requirements for such wells, i.e., set cement plug in the bottom of the tubing, shoot

off the tubing, and set cement plug across the tubing stub.

Response 3791:

For older wells completed in this fashion, the packer and cement plug would be removed (drilled

out) and plugging would proceed in accordance with the requirements of this Part.

Comment 3796:

Separate the requirements under Part 555.5(a)(2) pertaining to cemented casing, uncemented

casing that is removed, uncemented casing that cannot be removed, and requirements pertaining

to all wells, e.g., surface plugs.

Response 3796:

The Department agrees that the text related to surface plugs should be separated from the rest of

proposed Part 555.5(a)(2).

Comment 3798:

Part 555.5(a)(2): It is unclear to the United States Environmental Protection Agency what is

meant by "50 feet inside and 50 feet outside of the casing shoe." First, does this mean that there

must be a 50-foot plug placed inside the casing with the bottom at the shoe, and a 50-foot plug

placed between that casing and the next largest casing string or the wellbore with the bottom of

the plug at the depth of the casing shoe, or does this mean that a 100-foot plug must be placed

across the casing shoe, extending from a point 50 feet below the casing shoe to 50 feet above?

Second, this requirement appears to pertain to the production/long string casing that is typically

set at the bottom of the well. Thus, setting a plug 50 feet below the casing seat may not be

possible. Third, it also appears to pertain to casing that is cemented in the well, further confusing

the requirement to place cement "outside" the casing shoe.

Response 3798:

The text, "50 feet inside and 50 feet outside of the casing shoe" in proposed Part 555.5(a)(2) has

been revised to read, "50 feet below and 50 feet above the casing shoe." This requirement would

not apply to the base of the production string if such string is set (and cemented) to the bottom of

the hole.

Comment 3800:

The second sentence of Part 555.5(a)(2) should be modified to specify the minimum thickness of

the plug that must extend above the stub.

Response 3800:

The second sentence in proposed Part 555.5(a)(2) has been revised to indicate that a plug

approximately 50 feet in length be placed in and above the stub of the casing.

Comment 3802:

The third sentence of Part 555.5(a)(2) is unclear to the United States Environmental Protection

Agency. Does this sentence mean that the 100-foot plug is to be squeezed out of the

ripped/perforated casing such that the 100-foot plug is outside the casing that was not pulled, or

if the 100-foot plug must be inside the perforated/ripped casing with an unknown amount having

gone out of the perforated/ripped section? If the 100-foot plug is to be placed outside the casing

that was not pulled, how does the operator verify that a 100-foot plug was actually placed, i.e.,

that cement was not lost into the formation?

Response 3802:

The text in proposed Part 555.5(a)(2) referenced by this comment explains that, for uncemented

casing that cannot be pulled, the casing must be perforated 50 feet below the shoe of the next

outer casing and a 100-foot plug placed across that shoe. This would mean that a plug of at least

50 feet would extend above (i.e., inside the casing that cannot be pulled) the shoe of the next

outer casing. The Department recognizes that some cement may be lost to the formation below

the shoe of the next outer casing.

Comment 3804:

The United States Environmental Protection Agency suggests moving the last sentence of Part

555.5(a)(2) to a new paragraph as this paragraph (a)(2) appears to specify requirements only for

wells where casing is to be left. The surface plug must be placed in all wells. Putting the surface

plug requirement in this paragraph is confusing as the subsequent paragraphs discuss plugs to be

placed deeper in the well and before the surface plug. To the extent possible, the plugging

regulations should list the required plug placements sequentially from total depth to the surface,

as is indicated in the opening sentence of Part 555.5(a).

Response 3804:

The Department agrees with these suggested changes.

Comment 3806:

Part 555.5(a)(3) states "If casing extending below the deepest potable fresh water level shall not

remain in the ground, a cement plug of at least 50 feet in length shall be placed in the open hole

at a position approximately 50 feet below the deepest potable fresh water level." This

requirement is unclear to the United States Environmental Protection Agency since in deep wells

there will be several strings of casing that extend below the deepest potable fresh water level.

Response 3806:

This requirement would not apply to wells constructed with multiple casing strings set below the

deepest potable fresh water, if those casing strings were left in the ground.

Comment 3809:

Part 555.5(a)(4): define the term "drawn."

Response 3809:

The term “drawn”, as used in Part 555.5(a)(4), means “pulled”.

Comment 3810:

In Part 555.5(a)(4), at the end of the first sentence in the paragraph, add "(i.e., the casing seat)."

Response 3810:

The Department has incorporated this clarification.

Comment 3812:

In Part 555.5(a)(4), it is unclear to the United States Environmental Protection Agency whether

the top or bottom of the plug shall be placed immediately below the point where the lower end of

the conductor or surface casing shall previously have rested. It should also be noted that

conductor pipe often does not extend to 50 feet in depth.

Response 3812:

Comment noted. The 50-foot plug would be placed such that its top is immediately below the

casing seat.

Comment 3814:

In Part 555.5(a)(4), there is a typo in the last sentence of the paragraph. The Department should

replace "well" with "will".

Response 3814:

The Department has made this correction.

Comment 3815:

For Part 555.5(a)(5), it appears to the United States Environmental Protection Agency that the

requirement in paragraph 4 to use cement, sand, or rock sediment above the surface casing seat

plug and/or conductor seat plug and below the surface plug conflicts with the requirement in

paragraph 5 to use gelled fluid between plugs. In addition, there has been concern expressed with

using gel in the depth interval of aquifers, particularly in cases where the surface casing has been

removed or lacks integrity. The State of Pennsylvania specifically prohibits the use of gel as a

plugging material in this depth interval due to occasional problems with gel impacting local

water wells. The Department may want to consider a similar prohibition.

Response 3815:

Surface casing in New York State must extend to a depth at least 75 feet below the base of

potable fresh water. As described in proposed Part 555.5(a)(4), a cement plug of at least 50 feet

in length shall be placed so that the top of the plug is immediately below the casing seat, and the

hole above that point shall be filled with cement, sand or rock sediment or other suitable material

in such a manner as will prevent erosion of the well bore area and not interfere with normal soil

cultivation. The Department will modify the text in Part 555.5(a)(5) to indicate that gelled

spacers shall not be used in the interval between the top of the surface casing seat plug and the

bottom of the surface plug.

Comment 3821:

Part 555.5(c) appears to allow for abandoned well sites to go un-restored as long as the

landowner signs a release and no hazard is present. In determining whether or not no hazard

exists, does the Department take into account adverse impacts to the environment or is it public

safety concerns? Either way, the United States Environmental Protection Agency recommends

removing this waiver and requiring full site restoration after a well is plugged as specified on

page 5-144 of the rdSGEIS.

Response 3821:

The commenter is mistaken, in that Part 555.5 (c) addresses surface restoration of a well that is

being plugged and abandoned, not the restoration of an abandoned well site. For any site

disturbing greater than one acre, a well operator must maintain coverage under the SPDES

General Permit, and as described in Section 5.17 of the rdSGEIS (Well Plugging), such coverage

could only be terminated upon satisfactory completion of surface restoration activities at a well

site. The Department’s statutory and regulatory programs are designed to protect both public

safety and the environment.

Comment 4908:

Part 555: There is concern that the Department likely does not have the resources to adequately

monitor and enforce proper well plugging, abandonment, and oversight/inspection of abandoned

wells (the latter to ensure the plugs remain intact and the wells do not leak in the future). The

state has thousands of orphan wells that are not plugged. The Department cannot responsibly

allow additional well construction until the current backlog of unplugged abandoned wells has

been addressed. There also is concern whether the required financial security will be adequate

for all of the costs involved, and that residents and taxpayers will be left to pay the bills. By the

end of 2009, the state fund to plug wells contained about $208,806, but plugging the states

abandoned wells will cost between $76 and $530 million. The liability requirements and related

policies need to ensure that no wells can be abandoned without being capped, and that the

financial responsibility belongs to the drilling companies.

Response 4908:

The Department has recognized for some time that its personnel resources would be a limiting

factor on the rate of development of proposals for high-volume hydraulic fracturing. However, it

is not within the Department's sole discretion to either hire additional staff or increase funding

(bonding). The advisory panel assembled to advise the Department will assess the needs of all

agencies and make recommendations on staffing and funding. Proposed revisions to Part

552.1(b) would require that an applicant supply, on a plat accompanying the application

materials, the distance in feet from the surface location of a proposed well to the nearest non-

producing unplugged well (if same is within one mile). Any unplugged well so identified would

need to be annotated with additional pertinent information. Additionally, proposed revisions to

Part 560.3(a)(8) would require that an applicant provide "...identification of any abandoned wells

subject to Parts 550 through 559 of this Title within the proposed spacing unit and within one

mile of the proposed surface location of the well, and information on such wells, as specified by

the Department." Section 7.1.6 of the rdSGEIS discusses the Department's approach to

abandoned wells identified during the application process, and Section 8.2.3 discusses the

Department's enforcement authority.

Comment 4909:

Part 555: There is concern that not enough is known regarding the long-term stability and

integrity of high-volume hydraulic fracture wells that are plugged and the behavior of chemicals

and pollutants that remain in abandoned well systems. Proposed systems for leak detection and

monitoring are short-term. Long-term regulation, permitting, and monitoring of compliance is

necessary. Part 555 should include evidence-based standards for plugging the wells. As well, a

program should be established to inspect all abandoned, plugged wells for leaking and ensure

that leaking wells are expeditiously repaired. This program should continue at least 100 years

beyond the time the last gas or oil well in the state is discontinued, to protect groundwater.

Response 4909:

Comment noted. The Department agrees that post-plugging inspections are an important part of

an effective regulatory program. Such inspections are currently conducted by Department staff.

Comment 4910:

Parts 555.2(b) and 555.3: No extensions should be granted, ever.

Response 4910:

Changes to Parts 555.2 (b) and 555.3 have not been proposed at this time. However, the

Department is charged with ensuring the environmentally sound, economic development of New

York's non-renewable energy and mineral resources for the benefit of current and future

generations. The granting of extensions to shut-in or temporary abandonment status is but one

aspect of the Department’s broad authority to carry out this part of its mission.

Comment 4911:

Part 555.4: A representative of the Department should be at the well site during plugging and

abandoning. No exceptions.

Response 4911:

The Department agrees that its representatives should observe all well plugging operations, but

acknowledges that circumstances sometimes dictate that it is not always possible.

Comment 4912:

Part 555.4(d): No exceptions should be given for hardship, only for emergencies that threaten

the environment or public health or safety beyond the threats posed by everyday operations.

Response 4912:


Comment 4913:

Part 555.5: The United States Fish and Wildlife Service recommends that the Department

require evaluation logs (on the well casing and cement) for all wells to be plugged, and that this

not be a discretionary requirement. This evaluation would be important to determine the

integrity of the casing and cement along with the proper procedure and materials needed for a

successful plugging of the well.

Response 4913:

The Department agrees that quality cement bond evaluation logs are valuable tools in the

assessment of well integrity. However, it may not be prudent to mandate this costly procedure in

all cases. Older or abandoned wells may contain obstructions, such as production tubing, that

preclude the use of down-hole tools for logging. In other circumstances, some wells may have

been installed by driving casing, so there would be no cement to evaluate.

Comment 4914:

Part 555.5(a)(5): The phrase "or other department approved fluid" is too vague. The allowed

fluid, or its specific characteristics, should be specified.

Response 4914:

The Department disagrees with this comment. There are many engineered spacer fluids used in

well plugging, and new products continue to be designed and tested.

Comment 4915:

Part 555.5(a)(5): 8.65 pounds per gallon is roughly the density of water. It would seem that

something more substantial than muddy water is envisioned here, so this section requires

technical review and editing, as appropriate.

Response 4915:

At standard atmospheric temperatures and pressures, water’s average weight is approximately

8.33 pounds per gallon. The referenced (density) value of 8.65 pounds per gallon is a minimum

value; more importantly, these engineered fluids are designed to maintain their characteristic

density over time and under different subsurface stress regimes.

Comment 4916:

Part 555.5(c) should address other holes, too.

Response 4916:

Part 555, in its entirety, applies to all ECL 23 wells in New York State.

Comment 4917:

Part 555.5(c): No surface restoration requirements should ever be waived, under any

circumstances.

Response 4917:


Comment 4918:

The following risks have not been addressed in Part 555: Risks of explosions from existing gas

wells abandoned long ago that may not be properly capped, which has occurred in Bradford,

Pennsylvania near the site of recent hydraulic fracturing activity; and risks of explosion from

poorly capped wells created by hydraulic fracturing where well drillers did not follow the rules

and wells were not carefully inspected due to lack of qualified personnel.

Response 4918:

Well control issues are discussed in the rdSGEIS in Chapters 1, 5, 7 and 10. A discussion of the

April 2011 well-control incident in Bradford, Pennsylvania, which involved the uncontrolled

flow of hydraulic fracturing fluid during fracture stimulation, is presented in Section 10.2.1 of

the 2011 rdSGEIS.

Comment 4919:

Part 555 is not clear whether a well that might be reused in the future to extract gas from the

Utica Shale or other formations can remain unplugged until that time or must be plugged first

before it is reopened later.

Response 4919:

A well that is plugged and abandoned in accordance with the Department’s rules and regulations

may be re-entered and completed in a different formation, provided that all the requisite

application documents have been provided and a Permit to Drill can be issued by the

Department. Parts 555.3 and 555.4 address the time frames during which wells not in use can

remain unplugged.

Comment 6533:

The proposed regulations increase the overlap lengths for cement plugs in abandoned oil and gas

wells from 15 to 50 feet at several locations (6 NYCRR 555.5(a)). This increase in plug length is

an improvement but not sufficient or well planned in all locations. The regulation requires filling

with cement from total depth to at least 50 feet above the top of the shallowest formation from

which the production of oil or gas has ever been obtained in the vicinity (6 NYCRR 555.5(a)(1)).

But not all gas pockets have actually produced gas but could cause methane contamination if

they are not already sealed off by casing. The regulations should specify that the cement plug

below the deepest potable fresh water level should overlap the transition than be just below it

because even a short section of uncased well bore open to the salt water could mix into the well

and to above the fresh water line (6 NYCRR 555.5(a)(3)).

Response 6533:

The Department agrees that a cement plug set below the deepest potable fresh water should

extend into the potable fresh water zone.

Comment 6566:

Part 555: The regulations and the rdSGEIS mitigation measures should be revised to clearly

specify that plugging a well bore should be performed in a manner that ensures that all

hydrocarbons and fresh water are confined to their respective indigenous strata and prevented

from migrating into other strata or to the surface. All hydrocarbon-bearing strata should be

permanently sealed off by installing a cement barrier at least 100 feet below the base to at least

100 feet above the top of all hydrocarbon-bearing strata (200 plug). The plugging of a well

should include effective segregation of uncased and cased portions of the well bore to prevent

the vertical movement of fluid within the wellbore. A continuous cement plug must be placed

from at least 100 feet below to at least 100 feet above the casing shoe (200 plug). The operator

should be required to submit records to the Department to demonstrate that the well has been

plugged and abandoned in compliance with the regulations.

Response 6566:

This comment does not provide a technical basis for requiring a 200-foot plug in place of the

Department’s proposed 100-foot plug. ECL 23 provides the Department with broad authority regarding

the plugging of wells; this authority includes the ability to require timely filing of plugging reports.

Specifically, ECL 23-0305(8)(d) states that the the Department shall have the power to “Require the

drilling, casing, operation, plugging and replugging of wells and reclamation of surrounding land in

accordance with rules and regulations of the department in such manner as to prevent or remedy the

following, including but not limited to: the escape of oil, gas, brine or water out of one stratum into

another; the intrusion of water into oil or gas strata other than during enhanced recovery operations; the

pollution of fresh water supplies by oil, gas, salt water or other contaminants; and blowouts, cavings,

seepages and fires.”

Comment 6567:

The regulations and the rdSGEIS mitigation measures should be revised to require cement

quality standards, including the use of gas blocking cement. The regulations should require

tagging of all cement plugs and provide instructions on when additional cement evaluation tools

must be run.

Response 6567:

The Department agrees that the use of quality cements, including those containing gas-block

additives, is critical to a quality plugging job. It is important to note that the method of cement

emplacement is just as important as the quality of cement used. Part 555.5(a) states that the

Department has the discretion to require the tagging of cement plugs. See response to Comment

6566.

Comment 6568:

Part 555.5(a)(1) should be revised to state: The well bore, whether to remain cased or uncased,

shall be filled with cement from total depth to at least 50 feet above the top of the shallowest

formation from which the production of oil or gas has ever been obtained within 1,000 feet of the

well bore. Alternatively, a bridge topped with at least 50 feet of cement shall be placed

immediately above each formation from which the production of oil or gas has ever been

obtained within 1,000 feet of the wellbore.

Response 6568:

The Department disagrees with this comment, as there is no technical justification for the

comment’s specified 1,000-foot distance. The term “vicinity” provides greater flexibility to the

Department for its assessment and evaluation of a proposed plugging plan.

Comment 6569:

Part 555.5(a)(2) should be revised to state: For any casing left in the ground, a cement plug of at

least 100 feet in length shall be placed 50 feet below and 50 feet above the casing shoe .

Uncemented casing must be cut and pulled as deep as practical with a plug approximately 50 feet

in length placed in and above the stub of the casing. If the uncemented casing is unable to be

pulled the casing must be perforated 50 feet below the shoe of the next outer casing and a 100-

foot plug placed across that shoe. A 50-foot plug shall be placed at the surface.

Response 6569:

The Department agrees that, for clarity, the terms “above” and “below” should be used in place

of the proposed terms “inside” and “outside”.

Comment 7814:

Part 555.5(c) needs to state specifically that no waste from well operations, such as contaminated

soil, pit liners, etc., may be buried as part of the earth used to fill in any pit.

Response 7814:

The Department disagrees that waste handling measures should be added to Part 555. Parts 554

and 560 address the management of wastes associated with ECL 23 wells.

Comment 7815:

Part 555.6: The proposed express terms do not say whether Part 555.6 will remain unchanged.

Response 7815:

Changes to Part 555.6 have not been proposed at this time.

Comment 7816:

Part 555.5(a): There are two technical issues/problems with this section. 1. De-bonding

between rock and cement is expected to happen because of their different material properties. 2.

The modeling work behind the regulation assumes that the plug and the rock remain fully

bonded once the plug is sealed. Thus, it is highly likely that well plug failure will occur far in

advance of 150 years.

Response 7816:

This comment provides no factual basis for its claims related to cement-bond and well-plug

failure.

88: Part 556, Operating Practices

Comment 3084:

Part 556.2(c): Gas flaring should not be permitted and extensions of time periods should not be

allowed. Some reasons cited included -- gas flaring generates significant greenhouse gas

emissions and wastes natural gas resources. Technology has been developed to reduce emissions

of natural gas during well completions. These procedures collect the natural gas, filter it, and

place it into pipelines and tanks as an alternative to venting or flaring it. The technology used in

the process is not complex and is done by means of special temporary equipment brought to the

well site. Studies have shown that this approach increases gas industry profits and significantly

reduces the greenhouse gases produced during well completion.

Response 3084:

The Department will require, via permit condition, a reduced emission completion whenever a

gathering line and sales line are available during completion at any individual well or the multi-

well pad. See rdSGEIS Chapter 7. Gas flaring may also be necessary for safety purposes during

drilling and completion operations. See also response to Comment 3095.

Comment 3085:

Part 556.2(c): Require the well operator to limit flaring to the minimum amount necessary and

also find alternatives to flaring, such as storing the gas or using it to generate electricity.

Response 3085:


Comment 3086:

Part 556 should mandate the use of natural gas-powered trucks, drill rigs, compressors, etc., so

there would be no diesel in the fracking fluids or escaping into the air.

Response 3086:

The rdSGEIS would require well operators to specify the type of fuel and engines proposed for

use at a well pad and would require the diesel fuel used in drilling and completion equipment be

limited to ultra low sulfur fuel with a maximum sulfur content of 15 ppm. However, these are

SEQRA mitigation measures and are not proposed regulatory requirements. The Department

also lacks the authority to regulate the type of fuel used in trucks. In addition, it is incorrect to

imply that there is a connection between the fuel used in a truck, drill rig or compressor engine

and the content of additives used in the process of hydraulic fracturing. Aside from the fact that

there is no physical contact between fuel combusted in an engine’s cylinders and additives

introduced to the subsurface, proposed 560.6(c)(24) would prohibit the use of a diesel-based

hydraulic fracturing fluid for wells subject to Part 560.

Comment 3095:

Part 556.2(b): Gas should not be allowed to escape from any well (high-volume hydraulic

fracture or otherwise) and extensions of time periods should not be allowed.

Response 3095:

Existing 556.2(b) already specifies the conditions under which an operator may flare and the

changes proposed to subdivision 556.2(b) will clarify the procedures for the well operator to

obtain approval to flare. The Department agrees that it is undesirable to allow gas to escape in

the air; however, flaring (combustion) of gas produced for a well is necessary in some

circumstances. Therefore, it is appropriate for the Department to retain the discretion to allow an

extension of the time period specified in the regulations.

Comment 6577:

The Department needs to clarify 556.2(g)(1) to explain what is meant by any permanent change

in the well bore configuration and/or why this proposed requirement is necessary.

Response 6577:

Examples of permanent changes to wellbore configuration include, but are not necessarily

limited to, addition or removal of casing strings and new perforations. Deepening and plugging

back within the same producing horizon are covered in the regulations elsewhere but are also

permanent changes to the wellbore that do not require a new permit but which should be reported

and recorded. The Sundry Notice and Report is intended to inform the Department of these

changes and to create a record of them should there eve be a need to investigate the well’s

downhole condition (e.g., prior to plugging, if gas storage is proposed nearby, etc.).

Comment 6578:

Part 556.2(g)(3): If an operator needs to submit a Sundry Well Notice and Report form, then the

regulations should specify a reporting time requirement. Industry recommends that operators

submit the form quarterly or annually for work done within that period.

Response 6578:

As revised, 556.2(g) requires the Sundry Notice and Report for several operations that require

Department approval, including a change to previously approved plans, modification of the

wellbore path, modification of the bottomhole location, flaring and re-fracturing. In these cases,

the form must be filed in advance each time one of these operations is proposed, and the

operation may not commence ahead of the Department’s approval. In other instances, the form

is used to report activities that did not require prior approval but still require prior notice, and the

Department agrees that a time period would be appropriate and has modified the draft regulations

accordingly.

Comment 7817:

Part 556.2(c) needs to specify an efficiency standard for flaring of at least 98 percent.

Response 7817:

The Department respectfully disagrees that a 98 percent flaring efficiency standard is necessary.

The primary objective of flaring is to burn off the methane being produced from the well as a

safety measure. This goal is achieved from ignition of the flare and combustion of the gas.

Comment 7818:

Part 556.2(g)(2) seems unlimited in terms of the scope of possible changes that could be

requested. There should either be tighter language putting some limits on those changes or some

other way of providing notice and the opportunity to comment to interested parties of those

possibilities.

Response 7818:

See response to Comment 6577. The Sundry Notice and Report is intended for operations for

which an approval or advance notice to the department is appropriate, but which do not require

another permit.

Comment 7819:

Part 556.2(g): Operators should be required to submit the Sundry Well Notice and Report form

quarterly or annually for work done within that period.

Response 7819: See response to Comment 6578.

89: Part 560, Drilling, Operation, and Stimulation of Low Permeability Reservoirs

Comment 2865:

The National Park Service (NPS) requests that the Department revise proposed Part 560.3(b)(2)

to incorporate the following rdSGEIS recommendation: a bullet added on page A6-3 of the

Environmental Assessment Form (EAF) Addendum under Topographic map of area, under

Required Attachments, location of the legislative boundaries of units of the National Park

System and any other areas under federal ownership (the applicant should consult with the NPS

to determine the legislative boundary of a particular unit or area subject to the management and

control of the NPS).

Response 2865:

The EAF Addendum (Appendix 6, rdSGEIS) was amended to require the location of legislative

boundaries of units of the NPS. The Department is opting for now to not include this language

in proposed Part 560.3(b)(2).

Comment 2875:

Since it does not appear that 6 NYCRR Chapter V, Subchapter B already contains such a

requirement, the Department should add a provision to those already proposed that obligates the

applicant to identify the equipment that the applicant will have available to address anticipated

emergencies (such as, blowouts, hydrocarbon presence in the annulus outside the outer casing, a

loss of power, containment of a fluid release, etc.).

Response 2875:

The Department does not agree that it should promulgate new regulations which identify

equipment to be used in an emergency. The Emergency Response Plan (ERP) includes a

description of release, fire, and explosion prevention procedures and equipment. It is not

intended to provide an all-inclusive list of emergencies (or other non-routine incidents) and their

correlative responses.

Comment 3042:

The proposed regulations would require operators to report to the Department any non-routine

incident at a well pad. Given the description of non-routine incident contained in the proposed

regulations, Part 560.5(c), the potential breadth of this requirement seems excessive and

arbitrary. The Department should clarify the proposed regulations to confirm that incident

reporting is required only in the event of releases into the environment that pose a risk of

significant harm or circumstances presenting a significant risk to public safety.

Response 3042:

The Department cannot make a site-specific assessment of the risk of significant harm to the

environment or public safety until after the non-routine incident is reported.

Comment 3043:

The rdSGEIS and proposed regulations, 6 NYCRR 560.5(c), purport to provide the Department

with the authority to require immediate cessation of operations if it receives a water supply

complaint that coincides with certain non-routine well pad incidents. Cessation of operations

simply because a third-party complaint coincides with a non-routine incident would be excessive

and arbitrary. The proposed regulations and rdSGEIS should clarify that cessation of operations

would depend upon an established connection between the complaint and the incident, as well as

a risk of substantial harm from continued operation.

Response 3043:

Whenever a spill occurs, the Department would consider the need to require immediate cessation

of operations or immediate corrective action, regardless of complainant.

Comment 3422:

Part 560.2(b)(8): the definition of high-volume hydraulic fracturing should be revised to read

300,000 gallons or more of fresh water. This would encourage recycling of flowback and

production fluids.

Response 3422:

The definition of high-volume hydraulic fracturing in Part 560.2(b) has been revised. See

Response to Comment 3436 in Category 90: Part 750, State Pollutant Discharge Elimination

System (SPDES) Permits including permits for High Volume Hydraulic Fracturing

Operations. In addition, a requirement has been added to proposed 554.1(c)(1) which states,

“The owner or operator must state in its plan that it will maximize the reuse and/or recycling of

used drilling fluids, flowback water and production brine to the maximum extent feasible.” This

wording recognizes that on-site processing of hydraulic fracturing fluids and reuse may not

always be practical, technically viable and/or economical.

Recycling and reuse of flowback water is anticipated and encouraged by the Department. On-

site processing of hydraulic fracturing fluids and reuse may not always be practical, technically

viable and/or economical, and therefore it is not a requirement of the proposed regulations.

Comment 3423:

Part 560.2(b)(17): The definition of product contained in this section is inconsistent with the

definition of product in Part 550.3(an). The Department should clarify that this definition

supersedes the definition of product contained in 550.3(an) for purposes of high-volume

hydraulic fracturing.

Response 3423:

The Department does not agree that the two definitions of product need clarification as suggested

in the comment. Part 560.2(a) states that the general definitions in Section 550.3 apply to the

extent not superseded by this Part, i.e., 560.

Comment 3424:

Part 560.3(c)(1)(i) and(ii): The use of the term "additive product" in these sections is

inconsistent with the definitions and Environmental Assessment Form Addendum. It should be

revised to read chemical additive, by product name. The terms chemical additive and product are

both defined terms, whereas additive product is not.

Response 3424:

The Department has revised 560.3 to eliminate the use of the term “additive product” in favor of

either “additive” or “product” as appropriate. Note that these provisions are now in proposed

560.3(d), rather than 560.3(c), and that 560.5(h) has also been added, using consistent

terminology, to address hydraulic fracturing chemical disclosure following well completion.

Comment 3426:

Part 560.3(c)(1)(v): This requirement is vague and open ended. Halliburton Energy Services,

Inc. (HESI) believes that its Chemistry Scoring Index should be allowed to be used to meet this

requirement.

Response 3426:

The language, now found in Part 560.3(d)(1)(vii), does not preclude HESI from using its

Chemical Scoring System as long as its system as part of its submission.

Comment 3427:

Certain components of Industry state that they support Part 560.3(c)(2). The Department should

make it clear that service companies should be allowed to make the disclosures required by

560.3(c)(1). The regulatory language appears to suggest that could be the case, but it is not

explicit. The regulatory language that states "Records determined by the department to be

exempt from disclosure shall not be considered a well record for purposes of disclosure" is also

supported.

Response 3427:

The Department has clarified Part 560.3 to indicate that the required disclosures, now described

by Part 560.3(d)(1), can be made by operators, service companies, or chemical

suppliers/manufacturers, as appropriate and necessary. Additionally, similar language is included

in proposed Part 560.5(h). Comments regarding support for Part 560.3(c)(2) [now 560.3(d)(2)]

are noted.

Comment 3428:

Part 560.6(c)(26)(viii) relates to the records required to be maintained of the hydraulic fracturing

operation. It is suggested that the last sentence contained in 560.3(c)(2) be added to this

provision, or else that clarification be provided as to what level of detail regarding additives is

required in the records and the Department's Well Drilling and Completion Report.

Response 3428:

Part 560.6(c)(26)(viii) has been revised to specify that the records to be maintained by the well

owner or operator must include a list of all additives, by product name. Part 560.5(h) has been

added to address the specific hydraulic fracturing fluid information which will be required to be

disclosed following well completion, concurrent with the filing of the Well Drilling and

Completion Report. Language similar to that formerly in 560.3(c)(2), now in 560.3(d)(2), is also

included in Part 560.5(h). Also see response to Comment 6116.

Comment 3755:

Proposed regulation 560.5(a) would require, as a supplementary permit condition, that operators

provide the Department with an Emergency Response Plan (ERP) three days prior to well spud.

Copies of the ERP should also be submitted to all appropriate local government agencies

(including the local health department), in order to help these agencies better prepare for all

eventualities. The ERP also should include provisions specific to the transportation plan required

under proposed regulation 560.3(a).

Response 3755:

The Department does not agree that inclusion of transportation plan specifics in the ERP is

necessary. As described in Section 7.13 of the rdSGEIS, the ERP must include the identification

and evaluation of potential release, fire and explosion hazards, and the identity of a

knowledgeable and qualified individual with the authority to respond to emergency situations

and implement the ERP. After the SGEIS is finalized, dedicated staff within the Department

would serve as a focused resource for local citizens and governments. Local agencies interested

in the ERP’s on file with the Department could contact these staff for assistance.

Comment 3762:

Proposed regulation 560.5(c) specifies that all non-routine incidents of potential environmental

and/or public safety significance must be reported to the Department. This proposed regulation

should be expanded to include a mandate that the Department notify the New York State

Department of Health (NYSDOH) and the appropriate local health department immediately upon

the receipt of any non-routine incident that has the potential to affect public health.

Response 3762:

The Department is responsible for responding to any spill or other non-routine incident at a well

pad, including investigations to determine the extent of contamination when warranted by the

nature and magnitude of the incident. The Department would be involved at the outset in

investigating complaints from private well owners that coincide with or occur within a year of

hydraulic fracturing operations at any well pad. Otherwise, local health departments would refer

the complaint to the Department after ruling out other potential causes. In cases where water

well complaints do not coincide with nearby high-volume hydraulic fracturing operations, the

initial response is best handled by the appropriate local health office because of the myriad

possible causes and their expertise in dealing with such issues. The Department and NYSDOH

will continue to coordinate efforts with respect to alleged private water well contamination.

Comment 3764:

Part 560.5(d)(1) states that when testing residential water wells prior to well spud the operator

must test "for the parameters specified by the department." This vague wording leaves it unclear

as to whether the Department will specify parameters on a case-by-case basis, well-by-well

basis, or whether a fixed set of parameters will be established for all high-volume hydraulic

fracturing wells drilled and produced in New York State. It is essential that the regulations

require and define a fixed, minimum set of parameters (specifically, as a minimum those that

have been recommended by the New York State Department of Health, and listed in Table- 7:3

of the rdSGEIS).

Response 3764:

Part560.5(d)(1) has been revised as follows: “prior to well spud, the operator must make all

reasonable attempts to sample and test, at the operator’s expense, all residential water wells

within 1,000 feet of the well pad for the parameters specified by the department, which at a

minimum include Barium, Chloride, Conductivity, Gross alpha/beta, Iron, Manganese, Dissolved

methane and ethane, pH, Sodium, Static water level (when possible), total dissolved solids

(TDS), and volatile organic compounds (VOCs), specifically BTEX….”

The parameters in the proposed final rule must be included in any private well sampling that is

conducted. Operators may include additional parameters at their discretion.

Comment 3779:

Part 560.5(d): Water well testing appears to deviate from section 7.1.4.1, Private Water Well

Testing of the rdSGEIS. Section 7.1.4.1 outlines a schedule where the operator would have all

identified residential water wells within the area of concern sampled and analyzed prior to the

commencement of drilling for each well on a pad; sampled and analyzed three months after each

well has reached total measured depth (TMD) if there is to be a hiatus greater than three months

between reaching TMD and the next applicable milestone; and sampled and analyzed three

months, six months, and one year after the conclusion of hydraulic fracturing operations of each

well on the pad. 560.5(d) Water well testing only proposes sampling and analysis be completed

prior to well spud (paragraph (1) and "at other intervals specified by the department after the

well reaches total measured depth" (paragraph (3). When a primary concern surrounding the

high-volume hydraulic fracturing process is the potential contamination of residential water

wells, it is imperative the regulations adopt the recommendations of the rdSGEIS and plainly

state its schedule for sampling and analyzing.

Response 3779:

The Department acknowledges that in some cases the rdSGEIS is more detailed than a proposed

regulation. Mitigation measures contained in the Final SGEIS will be required and enforced as

permit conditions. This provides flexibility for other approaches to be implemented as operators

and the Department gain experience. While the rdSGEIS reflects those approaches that the

Department has determined would effectively achieve an environmental objective, there may be

other ways to accomplish the same objective that exist now or that will be developed as

technology advances. The Department always has the option to propose additional regulations

should a specific approach to a given objective become standardized or be deemed the only

acceptable alternative.

Comment 3789:

Part 560 in general: The Department should make the new regulations consistent for all

hydraulic fracturing, not just that where more than 300,000 gallons of water are used.

Otherwise, vertical oil and gas wells using less than 300,000 gallons of water will remain

grandfathered under outdated permitting conditions and will be allowed to use inferior casing

standards, open waste pits, and a regulatory framework that dates back to the 1970s.

Response 3789:

The Department does not agree with the commentor’s characterization of the existing regulatory

framework as antiquated. Wells using under 300,000 gallons of water do not have the same

magnitude of potential impacts as high-volume hydraulically fractured wells. Proposed Part 560

sets the high-volume threshold at 300,000 or more gallons of water for hydraulic fracturing per

well completion as such was identified as triggering known and/or potential impacts that require

enhanced well application information (i.e., rdSGEIS Appendix 6, Environmental Assessment

Form Addendum), and mitigation in the form of permit conditions (i.e., SGEIS Appendix 10,

Proposed Supplementary Permit Conditions for High-Volume Hydraulic Fracturing).

Comment 3792:

Proposed regulation 560.5(d)(4) must include the requirement that operators provide copies of

test results and documentation related to delivery of test results to local health departments, the

New York State Department of Health, and owners of the water wells tested. The operator shall

review the test results and include an analysis of whether there have been deviations from

baseline testing in a report to local health departments and New York State Department of

Health.

Response 3792:

The Department does not agree that the regulation should be changed as suggested in the

comment. Part 560(d)(1) already requires that the owner of any water well tested be provided

with a copy of the test results. Part 560(d) has been amended to require that the New York State

Department of Health be provided with a copy of test results and documentation related to

delivery. Copies of test results and documentation of delivery must be made available to the

Department upon the Department’s request.

Comment 3794:

Part 560.5(f) requires that the Drilling and Production Waste Tracking Form be completed and

retained for three years by the operator, transporter, and destination facility and be made

available to the Department, if requested. These forms are the companion pieces to the Fluid

Disposal Plan, which would be required by proposed 6 NYCRR 750-3.12(b) and will, in part,

demonstrate whether or not the Fluid Disposal Plan was implemented. Together, these forms

help identify the owner’s/operator's waste, waste management plans, and projections, and if

those were accurate. As such, the Drilling and Production Waste Tracking Form should be

publicly available.

Response 3794:

The Department agrees and has amended Part 560.5(f) to require the operator to make the

Drilling and Production Waste Tracking Form available to the public on the operator’s website

within 30 days of receipt of the waste by the disposal or treatment facility.

Comment 3801:

Part 560 in general: The proposed Part 560 regulations do not address greenhouse gas emissions.

At a minimum, applicants should be required to provide a description of planned greenhouse gas

emission control measures. Even more effective would be to require a greenhouse gas impacts

mitigation plan estimating anticipated greenhouse gas emissions at the well site and quantifying

the impact of proposed control measures. The regulations also should address greenhouse gas

emissions testing and reporting as described in the rdSGEIS. Two years after completion of the

first well drilled and completed, the Department should analyze the actual usage of Reduced

Emissions Completions; therefore, permits should require testing, recordkeeping, and reporting.

Site owners should be required to keep annual reports of compliance with the greenhouse gas

emissions leak detection program and make the reports available to the Department upon request.

Response 3801:

The rdSGEIS Appendix 10 proposed Supplementary Permit Conditions contain a requirement

for the submittal of a greenhouse gas (GHG) emissions plan. Included in the GHG emissions

plan is a leak detection and repair requirement (LDAR) whereby the operator must submit an

annual report to the Department and repair any discovered leaks within 15 days. See rdSGEIS

Chapter 7. The Department believes this level of reporting is adequate but not necessary for

inclusion in the regulations. This provides flexibility for other approaches to be implemented as

operators and the Department gain experience and as the technology evolves.

Comment 3807:

For proposed regulation 560.3(a)(6), the scaled distance from the proposed surface location of

the well and the closest edge of proposed well pad to any primary or principal aquifer boundary,

perennial or intermittent stream, wetland, storm drain, lake or pond, and any surface water body

that is a tributary to a public drinking water supply should be increased to 2,640 feet to be

consistent with other application requirements and recommended setback distances for these

resources.

Response 3807:

The Department respectfully does not agree that the setback distances must be the same for all

resources. The sensitivity of a resource to a given drilling activity will depend upon many

factors. Setbacks were developed by balancing the protection of the water resource, which is

achieved by many measures in addition to setbacks, and the policy in ECL §23-0301 to allow for

the recovery of the natural gas resources and to protect correlative rights. The magnitude of the

setback reflects the magnitude of the potential risk and the potential harm in the event of a spill.

Comment 3819:

Part 560.3(b), Mapping Requirements, should include a requirement for a map drawn at the scale

of 1:2,400 showing the locations as identified in published documents of faults and fracture-

intensive domains (FIDs) within one mile of the proposed edge of the well pad.

Response 3819:

See Section 6.1.6.2, Subsurface Pathways in the rdSGEIS, which describes the specific

conditions and analytical results supporting the conclusion that hydraulic fracturing does not

present a reasonably foreseeable risk of significant adverse environmental impacts to potential

freshwater aquifers, including via migration through faults. See rdSGEIS Appendix 10,

Proposed Supplemental Permit Conditions, which requires immediate suspension of hydraulic

fracturing pumping operations if any anomalous pressure and/or flow condition is observed such

as would be seen if a fault was encountered.

Lineament mapping may have some value but cannot provide the exact location of faults and

fractures. Surface lineaments also do not indicate whether or not a surface fracture is open at

depth. Surface mapping and investigation is necessary to confirm whether a lineament is in fact

a fracture or some other linear feature.

Comment 3822:

Part 560.3(b), Mapping Requirements, should include a requirement for a map drawn at a scale

of 1:24,000 that shows the primary and principal aquifers of concern. The existing statewide

geographic information system map (showing principal aquifers) is outdated and inaccurate as it

was digitized at a scale of 1:250,000 and has not been revised to include information from

numerous detailed aquifer studies that have been conducted since the map was digitized in the

1980s. There is >30% discrepancy between the aquifer boundaries mapped at scales 1:250,000

and 1:24,000.

Response 3822:

Additional mapping of principal aquifers at the 1:24,000 scale is warranted. The Department is

able to assist applicants with determining whether a proposed location is within the principal

aquifer boundary. The Department recognizes this concern and suggests that if a proposed well

location is within 2,000 feet of the principal aquifer boundary on a 1:250,000 scale map, the well

permit applicant must contact the Department for a determination.

Comment 3826:

In proposed regulation 560.4 (a), the prohibition of well pads should be expanded to include a

prohibition of well pads in the following areas: (1) closer than 1,000 feet from a private water

well unless waived by the water well owner; (2) within the geometric boundary of a primary

aquifer and a 2,000-foot buffer from the boundary of a primary aquifer or surface water divide

for the aquifer, whichever is closer; (3) within a 100-year floodplain and a 500-foot buffer of the

100-year floodplain; (4) within 500 feet of a wetland; (5) within 2,000 feet of any public water

supply (municipal or otherwise) well, reservoir, natural lake or man-made impoundment (except

engineered impoundments constructed for fresh water storage associated with fracturing

operations), and river or stream intake; (6) within 2,500 feet of any faults identified in published

documents or fracture intensification domains (FIDs) that are mapped within 1,000 feet of any

public water supply (municipal or otherwise) well, reservoir, natural lake or man-made

impoundment (except engineered impoundments constructed for fresh water storage associated

with fracturing operations), and river or stream intake; (7) within 1,000 feet of any active or

abandoned salt mine; (8) below a Finger Lake or dry Finger Lake valley and within 500 feet of

the Finger Lake; and (9) within 500 feet of a perennial stream.

Response 3826:

The Department does not agree that the commenter’s proposed prohibitions are necessary.

Existing Parts 550 – 559 regulations, the proposed Part 560 regulations and the

prohibitions/restrictions found in the rdSGEIS provide adequate protections for the public,

drinking water supplies, and the environment. The presence of FIDs or faults does not mean

these features are open and able to transmit fluids at depth. See also response to Comment

3828.

Comment 3828:

Proposed regulation 560.6(c)(20) should be expanded to require (prior to hydraulic fracturing

operations) the operator perform a down-hole 3-D seismic survey that covers the full extent of

the planned horizontal borehole. A record of the 3-D seismic test must be maintained on-site by

the operator and be available to the Department upon request.

Response 3828:

The Department will require a 3-D seismic survey prior to hydraulic fracturing operations or

active microseismic monitoring (sometimes referred to as down-hole 3-D fracture imaging)

during fracturing when the proposed objective formation top is less than 3,000’ true vertical

depth. See rdSGEIS Chapter 7. The Department does not agree that the proposed regulatory

expansion is necessary.

Comment 3831:

Part 560 in general: The rdSGEIS proposes mitigation measures concerning high-volume

hydraulic fracturing operations that are not addressed in these regulations (e.g. limiting emissions

from diesel engines, the greenhouse gas mitigation plan). The United States Environmental

Protection Agency Region 2 recommends that the Department include all applicable mitigation

measures in the regulations to improve their enforceability as well as provide one clear document

in English to which the regulated community, the regulators, and the public can refer to

determine applicable requirements.

Response 3831:










Comment 3832:

The 1992 GEIS describes use of up to 80,000 gallons of water for a typical hydraulic fracturing

operation. Part 560.2(b)(8) defines high-volume hydraulic fracturing as the stimulation of a well

using 300,000 gallons or more of water as the primary carrier fluid in the hydraulic fracturing

fluid. In order to be consistent with the GEIS, high-volume hydraulic fracturing must be defined

as the stimulation of a well using greater than 80,000 gallons of water as the primary carrier fluid

in the hydraulic fracturing fluid. This threshold as a definition based on average volumes for

each stage of shale drilling should be reevaluated based on what is documented in the 1992

GEIS.

Response 3832:

See Response to Comment 3436 in Category 90: Part 750, State Pollutant Discharge

Elimination System (SPDES) Permits including permits for High Volume Hydraulic

Fracturing Operations. The 1992 GEIS does not state or set a maximum volume of water used

for hydraulic fracturing operations. Instead, it describes a typical water-gel hydraulic fracturing

treatment known as “Water-gel fracs” as the most common stimulation technique. Twenty to

eighty thousand gallons of fluid are injected into the producing formation under high pressure. It

was ultimately determined by the Department that high-volume hydraulic fracturing and

potential associated impacts would not be triggered and realized until a volume of 300,000

gallons of water is reached or exceeded. All proposed water volumes below this threshold are

considered under the 1992 GEIS.

Comment 3833:

Proposed regulation 560.7(f) should classify flowback water as hazardous waste and subject it to

the corresponding regulations.

Response 3833:

Currently, “drilling fluids, production brine, and other wastes associated with the exploration,

development, or production of crude oil, natural gas or geothermal energy” are excluded from

being regulated as a hazardous waste in both federal law and federal and state regulations (42

U.S.C. 6921 (b)(2)(A), 40 CFR 261.4(b)(5), 6 NYCRR 371.1(e)(2)(v)). This is commonly

referred to as the “extraction and production” (E&P) exclusion. This exclusion has existed since

the beginning of the RCRA regulatory program and was included verbatim in the New York

regulations when USEPA delegated the RCRA program to New York. The exclusion was

conditionally included in the RCRA statute by Congress (Section 3001(b)(2)(A)). Congress

required USEPA to study these wastes and determine whether they should be regulated as

hazardous waste or not. USEPA reported to Congress in 1988 and concluded that regulation of

E&P wastes as hazardous waste was not warranted. USEPA provided several reasons for their

conclusion (53 FR 25446):

existing state and federal regulatory programs (including the Solid Waste Disposal

Act, Safe Drinking Water Act, Clean Air Act, and Oil Pollution Act) provided

adequate controls for the disposal of these wastes;

given that billions of barrels (volumes approaching one trillion gallons per year) of

these wastes are generated per year nationally, regulating these wastes under RCRA

would cause a severe impact on oil and gas production in the United States;

insufficient commercial treatment capacity would create serious short-term

implementation problems; and

regulating these wastes under RCRA would inhibit the exploration for new oil, gas,

and geothermal energy deposits.

The proposed regulations and permits provide provisions to prevent significant adverse impacts

from mismanagement of high-volume hydraulic fracturing wastes. Wastes must be handled and

stored in ways to minimize the potential for releases (e.g., secondary containment for flowback

fluids and standby vacuum trucks). Drilling operations must conform to setback requirements.

Transportation must be carried out by haulers permitted under Part 364. The disposal of wastes

must be tracked from generation to disposal using a Drilling and Production Waste Tracking

Form. Disposal of waste fluids must be in accordance with a variety of requirements,

particularly those under SPDES. Solid wastes must be disposed in accordance with Part 360.

Regulating high-volume hydraulic fracturing wastes as hazardous wastes would unnecessarily

increase the cost of regulation with little, if any, additional environmental benefit. It would also

likely eliminate the recycling of flowback water.

Comment 3834:

The definition of wetlands in Part 560.2(b)(26) should be revised to read: Any area regulated

pursuant to Article 24 of the Environmental Conservation Law; and federally regulated wetlands,

which are further defined as areas included under the definition of "waters of the United States"

at 33 CFR 328.3(b), which defines the term "wetlands" to mean "those areas that are inundated

or saturated by surface or groundwater at a frequency and duration sufficient to support, and that

under normal circumstances do support, a prevalence of vegetation typically adapted for life in

saturated soil conditions," and which are "navigable waters" as defined by Section 502(7) of the

Clean Water Act, 33 U.S.C. 1362(7).

Response 3834:

This definition in Part 560.2(b)(26) is consistent with the rdSGEIS and a definition of “wetlands”

that has been added to the HVHF General Permit: “any area regulated pursuant to Article 24 of

the Environmental Conservation Law and any other wetlands regulated under Section 404 of the

Clean Water Act.”

Comment 3837:

Part 560.4(a) should be revised to include the prohibition against high-volume hydraulic

fracturing operations within 4,000 feet of the New York City and Syracuse Watersheds as

recommended by Section 3.2.4 of the rdSGEIS. The regulations also should clarify if activities

associated with high-volume hydraulic fracture drilling and completions will be prohibited

underneath the watershed as well as on the surface.

Response 3837:

The Department would prohibit the construction of well pads within the 4,000-foot buffer

through the SGEIS. The 4,000-foot buffer is with respect to well pads and is not a prohibition of

horizontal drilling under the buffer or the watershed itself.

Comment 3842:

Part 560.4(a) should be modified to include the requirement under Section 3.2.5 of the rdSGEIS

that site-specific environmental assessments and State Environmental Quality Review Act

determinations of Significance are required for the following high-volume hydraulic fracturing

projects: 1. Any proposed well pad within 500 feet of a principal aquifer; 2. Any proposed well

pad within 150 feet of a perennial/ intermittent stream, storm drain, lake, or pond; and 3. Any

proposed well location within 1,000 feet of the New York City Department of Environmental

Protection's subsurface water supply infrastructure.

Response 3842:

The Department does not agree that it is necessary to promulgate SEQRA determinations as

regulations. They will be formalized in a Findings Statement that will be issued after the SGEIS

is finalized.

Comment 3843:

Part 560.4 Setbacks: The Department should include a requirement prohibiting well pad sites on

steep slopes.

Response 3843:

The draft stormwater general permit for high-volume hydraulic fracturing specifies that general

permit coverage is not available on steep slopes. An individual SPDES permit would be required

for steep slopes which would provide a mechanism for addressing potential stormwater

management and erosion control issues.

Comment 3845:

Part 560.5 Testing, Recordkeeping and Reporting Requirements: The Department should

consistently require that private water well test results be submitted to the Department. The

Department should consider establishing a groundwater baseline database and follow-up with the

entry of post-initial sample results.

Response 3845:

Part 560.5 has been revised to require that private water well testing data be submitted to the

NYSDOH and be made available to the Department upon request. Establishment of a

groundwater baseline database is beyond the scope of the proposed rules. See also Response to

Comment 3792.

Comment 3847:

In accordance with Page 7-45 of the rdSGEIS, Part 560.5(d)(1) should be revised to clarify that

initial sampling and analysis of residential water wells must occur prior to site disturbance at the

first well on the pad and then prior to drilling commencement at additional wells on multi-well

pads.

Response 3847:

Part 560.5(d)(1) has been amended.

Comment 3848:

The proposed Part 560 regulations do not address mitigation measures that the rdSGEIS says will

be required for wildlife, grasslands, forest integrity, and the spread of invasive species.

Response 3848:










Comment 3849:

Part 560.5(d) should specify in accordance with page 7-47 of the rdSGEIS that the water samples

be collected by a qualified professional and analyzed utilizing a laboratory approved by the New

York State Department of Health's Environmental Laboratory Approval Program, including the

use of proper sampling and laboratory protocol, in addition to the use of proper sample

containers, preservation methods, holding times, chain of custody, analytical methods, and

laboratory quality assurance/quality control.

Response 3849:










Comment 3850:

In accordance with Paragraph 54 of Appendix 10 of the rdSGEIS, Part 560.5(g) should be

modified to include not only the intended destination of any fluid or other waste material moved

off site by pipeline but its intended disposition and use at that destination or receiving facility.

Response 3850:

Part 560.5(g) has been amended.

Comment 3851:

Part 560.6(a)(4) should be revised to include the proposed requirement specified on page 7-37 of

the rdSGEIS that pit liners must be constructed, coated, or lined with materials that are

chemically compatible with the substance(s) stored and the environment as well as the

requirement for freeboard monitoring.

Response 3851:

Part 560.6(a)(4) has been modified to require pit liner compatibility with stored substances. The

requirement for freeboard is included in the Supplementary Permit Conditions of the 2011

rdSGEIS.

Comment 3852:

Part 560.6(b)(1)(ii) appears to allow fueling tanks within 500 feet of a perennial or intermittent

stream, storm drain, wetland, lake, or pond if longer distances are not considered practical by the

operator. This is inconsistent with the recommendation to completely prohibit such siting of

fueling tanks in Section 7.1.3.1 of the rdSGEIS. Therefore, delete the phrase "to the extent

practical" and increase the allowed distance between fueling tanks and the water sources listed,

taking into account topography, slope, and other factors.

Response 3852:

The Department has deleted the phrase “to the extent practical” and will evaluate fuel tank and

other equipment placement during its review of the proposed application to drill.

Comment 3854:

Part 560.6(c)(15) states that remedial cementing will be required if the cement bond is not

adequate for drilling ahead. Part 560.3(a)(16)(iii-iv) indicates that any casing and casing seat

integrity testing plans must be submitted as part of the permit application. It is unclear if these

tests are required but, in any case, if such tests are run, the results of those tests should also be

considered when determining if remedial cementing of any casing string is necessary.

Response 3854:

Comment noted. The Department will evaluate all test information available in order to

determine whether remedial cementing of casing is required.

Comment 3856:

Part 560.6(c)(16) specifies that if intermediate casing is installed, the production casing cement

must be tied into the intermediate casing string with at least 300 feet of cement measured using

True Vertical Depth. This requirement is unclear as it could be interpreted to mean: (1) The

production casing must have a minimum 300 feet of cement above the casing shoe and must tie

into the intermediate string of casing by an unspecified amount, e.g. 10 feet; or (2) The cement

outside the production casing must extend a minimum of 300 feet above the casing seat for the

intermediate string of casing. Thus, it is recommended that the Department clarify the language.

Response 3856:

The cementing language has been clarified to require that the production casing cement must

extend a minimum of 500 feet above the intermediate casing seat.

Comment 3857:

Part 560.6(c) should clarify whether or not pressure testing of the casing and casing seat integrity

tests as referenced in the permit application requirements in Part 560.3 are required. If hydraulic

fracturing operations are occurring down tubing set on a packer [Part 560.6(c)(21)], the

tubing/casing annulus should be pressure tested to ensure that the packer has a good set that can

withstand hydraulic fracturing pressures, the tubing is sound, and the production casing is sound

and can withstand hydraulic fracturing pressures in the event a tubing or packer failure occurs

during hydraulic fracturing operations.

Response 3857:

The Department believes the test requirements do not need to be included in the Part 560

regulations. Appendix 10 of the rdSGEIS, Proposed Supplementary Permit Conditions, requires

pressure testing of casing, injections lines, hydraulic fracturing treating equipment, wellhead

components and casings, injection lines and manifold, associated valves, hydraulic fracturing

head or tree and any other wellhead component or connection. The Department will utilize the

BOP Use and Test Plan to evaluate all pressure tests during drilling and will also evaluate

breakdown pressure data. An unacceptable loss of pressure during the test (> 10%) indicates the

injection string packer was not seated properly and any failed test must be reported to the

Department along with the operator’s plan to remediate the problem.

Comment 3859:

Part 560.6(c)(28) should be modified to state that the flare stack must be at least 30 feet in height

unless the absence of hydrogen sulfide has been demonstrated at a previous well pad which was

completed in the same producing horizon. In some parts of New York State, the Marcellus and

Utica formations are both potential targets, so one well pad may be home to wells completed in

the Utica and the Marcellus.

Response 3859:

Part 560.6(c)(28) has been amended.

Comment 3860:

A sentence should be added to Part 560.7(e) clarifying that no waiver of these reclamation

requirements shall be granted when such well pad or access road was constructed in wetlands.

Response 3860:

The Department does not agree that the proposed statement should be added to Part 560.

However, the SGEIS recognizes that wetlands are sensitive resources requiring enhanced

protection. Additionally, in response to this comment and others concerning wetlands and other

sensitive water resources, the Department proposes in its revised rulemaking under 6 NYCRR

750-3 to increase the setback of well pads from wetlands from 100 to 300 feet. Additionally, the

construction of a well pad or access road in wetlands would require an Article 24 wetlands

permit and the operator would be required to comply with additional permit conditions.

Comment 4401:

The proposed regulations do not address measures to prevent seismic impacts.

Response 4401:

The rdSGEIS has characterized the risks of seismicity impacts from high-volume hydraulic

fracturing as low with essentially no increased risk to the public, infrastructure or natural

resources from induced seismicity related to hydraulic fracturing.

Comment 4402:

The proposed rules provide no protection against the pollution and environmental damage that

gas drilling and hydraulic fracturing have already caused. [This is shown by] pollution

[incidents] that have occurred [in other places], despite promises that there was no danger.

Response 4402:

The proposed regulations contain many proposed requirements to prevent and reduce potential

significant adverse impacts to natural resources. The Department believes that these

requirements would prevent and reduce significant adverse impacts to environmental resources

including water quality, habitat quality, and the spread of invasive species.

Comment 4405:

Part 560.4: Water well owners should not be allowed to waive the requirement of the 500-foot

setback. A decision by a private landowner to waive the requirement endangers water quality for

that aquifer. As well, the regulation should state that any attempt to waive or vary from

requirements will automatically be a Type I action under the State Environmental Quality

Review Act.

Response 4405:

The Department does not agree that a decision by the landowner to waive the 500-foot setback

will endanger the water quality for the aquifer. The protections and requirements found in the

rdSGEIS, Environmental Conservation Law and Regulations provide protection to the aquifer

and the environment. Likewise the Department does not agree that an attempt to waive the 500-

foot setback should require that the action be classified as Type 1.

Comment 4407:

Part 560.4: A 500-foot distance from a primary aquifer is not adequate. Just as in the case of

New York City and Syracuse, the setbacks should be 4,000 feet from the boundaries of the

watershed, not just the aquifer itself.

Response 4407:

The New York City and Syracuse drinking water supply watersheds have a 4,000-foot well pad

prohibition from their boundaries due to the exclusion of communities with Filtration Avoidance

Determinations (FAD). The Department believes that the circumstances unique to FAD

watersheds warrant the larger setbacks compared to primary aquifers.

Comment 4409:

Part 560.4: Setbacks from sole-source aquifers are not addressed. Cortland County has a sole-

source aquifer that serves 39,000 people. Unlike a primary aquifer, the boundaries of a sole-

source aquifer include its watershed. Given the fact that the very designation of being a sole-

source aquifer means that there is no other economically feasible water supply for that area, a

sole-source aquifer deserves the same protection that is given to the New York City and

Syracuse watersheds, i.e., a 4,000-foot setback from the boundaries.

Response 4409:

See response to Comment 4407. The Department has taken the position that there is no direct

technical relationship between the designation of “Sole Source” Aquifers and Primary and

Principal Aquifers (see http://www.dec.ny.gov/lands/36151.html).

Comment 4554:

The Department should amend the following provision that poses a safety hazard. Part

560.6(c)(19) states: "Under no circumstances should the annulus between the surface casing and

the next casing string be shut-in, except during a pressure test." This requirement is not good

practice and is in fact a safety and environmental hazard, as it could lead to surface pollution,

fire, or a blowout. A better general rule would be to require an appropriate gauge and release

valve.

Response 4554:

The Department does not agree. The concern with shut-in of the annulus between the surface

casing and the next string (typically intermediate casing in wells where high-volume hydraulic

fracturing is used) is possible gas buildup and pressure at the surface casing seat resulting in

movement outside of the surface string, and possible risk to freshwater intervals.

Comment 4555:

Several provisions in Part 560 describe ambiguous or vague standards and requirements. For

example, Part 560.6(c)(1) mandates that a required well prognosis be revised by the operator if

drilling reveals significant variation between anticipated and actual geology/formation pressures,

but no clarification or guidance is given as to the interpretation of "significant" in that context.

Part 560 uses the word "adequate" without any clarification or guidance a total of eight times

(e.g., pit sidewalls and bottoms must be adequately cushioned.)(see 560.6(a)(4)(iii)). This loose

phrasing increases regulatory uncertainty and decreases the likelihood that all operators will

follow appropriate procedures and observe the intent of Part 560. Along the same lines, in order

to clarify operator obligations and ensure appropriate practices, Part 560 should enshrine specific

operational standards and American Petroleum Institute (API) standards wherever possible and

appropriate, including in place of the term "industry standards" in Parts 560.6(c)(3), (4), and

(10).

Response 4555:

http://www.dec.ny.gov/lands/36151.html

The Department does not agree that the use of terms such as adequate or significant will create

regulatory uncertainty resulting in the likelihood of decreased compliance with the requirements

of Part 560. Department staff will perform inspections during all phases of drilling to ensure

compliance, verify adequacy of the well site components and to verify the status of the “as

drilled well” versus the prognosis. The use of seismic and other data along with the blanket

nature of shale formations leads the Department to believe that significant variations will be rare.

As with other permitting programs, communication of a variation event from the anticipated

prognosis is essential. References to conforming to or being in accordance with API standards

are found in Appendix 10 and 25 which include casing, thread compound, centralizers, cement

and well logging and other testing. An industry standard that conforms with API standards or is

equally protective is also acceptable to the Department. Enshrinement of “API standards”

language is not necessary.

Comment 4556:

Some of the provisions in Part 560 call for blanket technology solutions that may not be

appropriate for all wells. For example, Part 560.6(c)(13) sets forth the blanket rule that

intermediate casing must be installed in the well. That intermediate casing should be used more

often than it is used currently, and in New York all wells that undergo large-volume hydraulic

fracturing should have intermediate casing, but it is not certain that this is the case and therefore

the Department is encouraged to consider whether it may be desirable to set forth clear

guidelines describing the circumstances where intermediate casing is and is not required.

Response 4556:

The rdSGEIS’ Proposed Supplementary Permit Conditions for High-Volume Hydraulic

Fracturing, Chapter 1 and Chapter 7 contain language regarding an operator’s request or ability

to waive the intermediate casing requirement. The operator must make its case for the waiver

and obtain Department approval to do so.

Comment 4557:

Part 560 contains several provisions for on-site pits that should be re-examined. Part

560.6(a)(4)(iv) states that any reserve pit, drilling pit, or mud pit on the well pad which will be

used for more than one well that is constructed in unconsolidated sediments must have beveled

walls of 45 degrees or less. All earthen pits should meet this requirement, not just those

constructed in unconsolidated sediments. Part 560.6(b)(2) states that except for freshwater

storage, fluids must be removed from any on-site pit prior to any 45-day gap in use and the pit

must be inspected by the department prior to resuming use. This requirement could limit water

reuse and recycling to the extent that multi-use pits are utilized. The Department should consider

adding a narrowly drawn exception provision.

Response 4557:

The Department will require beveled walls of 45 degrees or less for all earthen pits. The

Department does not agree that the requirement that fluids must be removed from any on-site pit

prior to any 45-day gap would limit water reuse and recycling. The operator must plan

accordingly to take the 45-day gap into account when drilling subsequent wells on a multi-well

pad.

Comment 4558:

Part 560 should place greater emphasis on wellbore integrity and certain operational issues. The

draft Model Regulatory Framework (attached to comment; MRF for Hydraulically Fractured

Hydrocarbon Production Wells) goes into great detail on these topics. In particular, although the

Environmental Defense Fund (EDF) does not endorse the MRF draft in all respects, EDF feels

that Part 560 should be revised to the extent necessary to cover adequately those operational

issues addressed in Articles IV through VI of the MRF, including but not limited to the following

MRF topics: The casing strength and composition requirements set forth in Section 2(a) of

Article IV; The well-head assembly and blowout preventer requirements set forth in Sections

2(b) and (c) of Article IV; The mud and drilling fluid requirements set forth in Sections 2(d), (e),

and (f) of Article IV; The surface, intermediate, and production casing requirements set forth in

Sections 4 through 6 of Article IV; The cement quality requirements of Section 4(d) of Article

IV; The use of only state-approved cementers and service companies pursuant to Section 7 of

Article IV and Section 4 of Article V, respectively; The pre-hydraulic fracturing pressure,

cement integrity, and surface equipment testing requirements of Section 2 of Article V; The

hydraulic fracturing job monitoring and reporting requirements of Section 3 of Article V; The

production and well monitoring requirements of Article VI; and The additional requirements for

operations involving close proximity wells set forth in Sections 4(h) and 6(h) of Article IV and

Section 2(d) of Article V. Rather than conceiving of close proximity wells as those that are 500

feet beneath the base of protected water, as is done in the current MRF draft, EDF suggests that

the Department consider using 1,000 feet.

Response 4558:


regulation. This provides flexibility for other approaches to be implemented as operators and the

Department gain experience. However, mitigation measures contained in the Final SGEIS will be

required and enforced as permit conditions. In some instances the Department added language to

incorporate EDF’s proposed requirements to the draft document. The rdSGEIS and its

appendices contain many of the requirements proposed in the Model Regulatory Framework

(MRF). Examples include but are not limited to: casing specifications, testing of casing, testing

wellhead and other equipment, waiting on cement time, cement compressive strength, BOP tests,

conformance with API specifications, monitoring the well during fracture operations, and the

volume of annular cement necessary to prevent vertical migration of fluids. In several cases the

Department’s requirements and standards exceeded EDF’s proposed revisions; therefore, the

Department determined that it would not incorporate EDF’s revisions for those items. A partial

list of the Department’s more stringent requirements include: no used or reconditioned casing

allowed for high-volume hydraulic fractured wells, 3-day pre-fracture notification instead of 24

hours notice, cementing of intermediate casing to the surface, running a full string of production

casing run to the surface (no liners) and an approximately 1,200-foot separation for wells in close

proximity to the freshwater zones instead of EDF/MRF’s 500 to 1,000 feet. The State holds the

operator responsible for the actions of its contracted service providers such as service and

cementing companies. The Department believes the SGEIS, once it is finalized, along with the

Environmental Conservation Law, and regulations will adequately protect the public, water

resources and the environment.

Comment 4559:

A clarification of what is meant by flowback fluids is suggested. The term is defined in Part

560.2(b)(7) as liquids produced following drilling and initial completion and clean-up of the well

or clean-up of a well following a re-fracture or workover. The Department should specify if this

is intended to include only the production brine that comes out of the well immediately after

completion or re-fracture, or if production brine surfacing long after the initial completion or re-

fracture is also included. This ambiguity could lead to operator uncertainty.

Response 4559:

The term has been amended to “flowback water.” Relatively small amounts of production brine

may be produced during initial completion and clean-up of a well. However, production brine as

it is defined in Part 560.2(b)(18) means liquids co-produced from oil and gas wells during the

production phase of the well. The Department does not agree that the term flowback water needs

clarification.

Comment 5794:

The proposed regulations refer to an "operators designated representative." However, that term is

not defined in any of the regulatory proposals. It is recommended that a definition be included in

560.2 as follows: designated representative means a person employed by the permittee or an

agent contracted with the permittee to oversee compliance at the well site.

Response 5794:

The Department prefers this designation be made on a permit and site specific basis to allow for

changes in relationships, responsibilities and preferences, and will therefore not amend the

regulations as suggested in this instance.

Comment 6086:

Part 560.2(b)(1): Use the term "technical standards" in place of "best management practices."

Response 6086:

The term “best management practices” is used by industry, regulators and various agencies

within the Department and is appropriate for use in the proposed regulations.

Comment 6087:

The Part 560.2(b)(8) definition for high-volume hydraulic fracturing should be revised to add the

word cumulatively in order to be more consistent with the Part 750-3.2 (b)(22) definition.

Without the conditional "cumulative" wording, the definition could pertain to each separate

fracturing stage (which may each be under the 300,000 gallon threshold).

Response 6087:



Fracturing Operations. Part 560.2(b)(12) has been amended to make it clearer that the volume

threshold applies to each well completion (which may consist of multiple hydraulic fracturing

stages).

Comment 6088:

The proposed 560.2(b)(12) definition of partial reclamation differs from the proposed 750-

3.2(35) definition. Moreover, the concept of partial site reclamation is unclear in both. This is an

important issue because of the episodic nature of drilling and completion associated with shale

development. When clarifying the definition in proposed 560.2(12), industry needs a reasonable

time frame to comply with the partial reclamation requirement and recommends six months.

Response 6088:

Partial reclamation operations must commence after completion of the last well on the wellpad.

The time necessary to do so may vary considerably based upon the time of year reclamation

activities begin and the length of the growing season. For these and other reasons a set time

frame was not proposed. Six months may or may not be adequate to partially reclaim the site.

The Department will review the proposed regulations for consistency prior to finalization.

Comment 6089:

Parts 560.2(b)(14) and (16): The Department continues to illogically distinguish between

principal and primary aquifers. Regardless of what population density is served by an aquifer,

the mechanism of protection should be identical. By suggesting that principal aquifers deserve

less protection because they serve a secondary human purpose condemns future New Yorkers to

potentially more resource constraints when potable water supplies become scarce.

Response 6089:

Setbacks have been recommended in order to conservatively provide a margin of safety should

the operational mitigation measures fail or not be implemented in a particular instance.

Additionally, setbacks were developed by balancing the protection of the water resource, which

is achieved by many measures in addition to setbacks, and the policy in ECL §23-0301 to allow

for the recovery of the natural gas resource and to protect correlative rights. The prohibitory

setbacks are for current drinking water supplies, including unfiltered drinking water supplies and

Primary Aquifers serving large numbers of residents and major municipal systems. A site-

specific SEQRA review is more appropriate for Principal Aquifers, as they generally serve

smaller numbers of residents than Primary Aquifers, and other water resources that are not used

as drinking water supplies. The Department always has the option to propose additional

regulations should additional protections to aquifers become necessary.

Comment 6090:

A public water supply is defined in Part 560.2(b)(19) as a well system that provides water for

human consumption to at least 5 service connections or to at least 25 persons per day at least 60

days per year. These definitions suggest that a well providing water to 1 to 4 buildings that are

not residences and that seldom provide drinking water to more than 25 persons per day would

not be covered under these regulations.

Response 6090:

The Department agrees.

Comment 6091:

Parts 560.2(b)(19) and (20): Clarify that a public water supply can consist of groundwater and/or

surface water.

Response 6091:

The Department does not agree that Parts 560.2(b)(19) and 560.2(b)(20) need further

clarification.

Comment 6092:

The definition of water well in Part 560.2(b)(23) is inconsistent with usage elsewhere in Part

560. Part 560.2(b)(23) states that a water well shall mean any residential well used to supply

potable water. However, Parts 560.5(d)(1), (2), and (3) all use the term residential water wells,

which implies that there may be other (non-residential) water wells in the area under

consideration. Perhaps it would be better to remove the terms residential and potable and have

the definition apply to all water wells.

Response 6092:

Comment noted. The Department deleted the water well definition found in Part 560.2(b)(23).

The Department will review the proposed regulations for consistency prior to finalization.

Comment 6093:

Part 560.2(b)(25): This definition of well site seems to create ambiguity allowing well pad

features (equipment and staging) to exist away from the pad.

Response 6093:

The revised proposed rule has been amended to clarify the intent of the term.

Comment 6094:

The proposed water regulations at 750-3.4 contemplate similar application requirements to those

proposed in 560.3, but they vary somewhat. Industry recommends that all of the application

requirements be contained in the minerals regulations and the singular application requirements

serve as a checklist for a complete application and compliance with the 1992 GEIS and the

rdSGEIS. There should be one-stop shopping at the Department.

Response 6094:

Comment noted. The Department will review the proposed regulations for consistency prior to

finalization.

Comment 6095:

Part 560.3: The application for a permit should include a graphical illustration of a model site,

showing grading, run-off contouring, drainage routing, use of berms, sills, and other barriers to

achieve containment, and all measures used to avoid drainage toward streams and wetlands. It

would also illustrate specific site locations for vehicle and equipment storage, fueling, cleaning

and maintenance; chemical and materials storage, mixing, handling, loading and unloading, and

cement mixing; lumber storage and processing; and a closed system of water-tight steel tanks for

supply of water for drilling fluids, hydraulic fracturing, and flowback.

Response 6095:

The Department does not agree that a graphical illustration containing all of the above items is

necessary for review of the application to drill. The Department’s plat and map requirements

found in Section 552.1, 560.3 and the proposed EAF Addendum (rdSGEIS Appendix 6) provide

adequate information for the evaluation of the drilling permit.

Comment 6096:

Part 560.3(a)(2): The operator should also be required to complete geophysical logging

including conductivity measurements to verify the depth of potential fresh water, unless it had

been based on previous drilling on the well pad.

Response 6096:

Part 560.6(c)(11)(ii) would require the use of geophysical logging to determine the base of

potable water.

Comment 6097:

Part 560.3(a)(3): The operator should also be required to discuss and specify how the estimated

volume of water (to be used in hydraulic fracturing) was determined.

Response 6097:

Part 560.3(a)(3) requires an operator to provide “the basis for the estimate of proposed total

volume of fluid,” which includes the total volume of fresh water and other water based fluids.

See also revised regulations at 750-3.8(c), which require monitoring and recording provisions in

the HVHF SWPPP for the volume of water used for each HVHF stage.

Comment 6098:

Parts 560.3(a)(5) and (6): The application should provide the distance to the water supply

features in (5) and the aquifer and stream features in (6) if they are within two miles.

Response 6098:

The Department disagrees. The EAF Addendum would require an applicant to provide scaled

distances from the proposed surface location of the well and the closest edge of the proposed

well pad to these features if they are within 2,640 feet, which is sufficient to ensure that the

proposed setbacks are met.

Comment 6099:

Parts 560.3(a)(5) to (8), 560.4, and 560.6(b)(1)(ii): Revise the regulations to specify that, where

there is slope or grade that may potentially cause materials from gas production-related activities

to migrate toward or enter said water resources, any potential sources of contamination such as

storage containers, facilities, equipment, holding ponds, access roads, storage lots, and other

facilities may be located no closer than 2,640 feet from the topographical boundary or ridge

where the slope or grade will not cause materials to reach the water resources. Potential sources

of contamination should be considered to include loose soil; mud runoff; lubricants; discharged

or vented materials; chemically treated water or produced water; cuttings; spills; proppant; stored

chemicals; reserve pits; and flowback storage.

Response 6099:

The Department disagrees. The proposed regulations and the rdSGEIS present a multitude of site

controls to protect water resources. The potential sources of contamination listed in this

comment and the proposed mitigation measures to address them are discussed in the rdSGEIS in

Chapters 6 and 7, respectively.

Comment 6101:

Parts 560.3(a)(5), (6), (7), and (8) do not require enough information. All surface waters, aquifer

boundaries, wetlands, wells, springs, location of fueling tanks, and other equipment should be

mapped for the entire drilling unit, as well as for a distance beyond the unit. This is important,

especially considering that laterals could extend anywhere within the unit.

Response 6101:

Part 560.3(a)(7) has been amended in order to be consistent with the rdSGEIS. Fueling tanks are

prohibited from being placed within 500 feet of a public or private water well, domestic supply

spring, reservoir, perennial or intermittent stream, storm drain, wetland, lake or pond. These

requirements are focused on the well pad where the equipment is located and activity occurs.

The direction and extent of the lateral well bores has no bearing on surface setbacks measured

from the well pad.

Comment 6102:

Part 560.3(a)(7): The United States Fish and Wildlife Service (USFWS) is concerned that

locating drilling rig fuel tanks at least 500 feet from streams, wetlands, and other bodies of water

is far enough. This distance might not be protective enough for aquatic habitat should a spill or

release of fuel occur in certain instances, such as on slopes. USFWS recommends increasing the

distance to more than 500 feet.

Response 6102:

Protection of streams, wetlands, and other bodies is achieved with the 500 foot setback and

secondary containment in proposed Part 560.6(b)(1). Setbacks that are delineated in the

proposed regulations are designed to ensure that significant adverse environmental impacts are

part of a multi-barrier approach avoided or mitigated to the greatest extent practicable. The

Department believes that the 500-foot setback is adequate in light of the other controls required.

Comment 6103:

Part 560.3(a)(9): There is concern that the gas companies and the Department will not be able to

locate and identify abandoned wells within the proposed spacing unit and within one mile of the

proposed surface location as the rule requires. Before high-volume hydraulic fracturing takes

place, the Department needs to find all of the abandoned wells in the state, map them, inspect

them, and ensure they have been plugged and are not leaking.

Response 6103:

Proposed Part 560.3(a)(8) would require applicants to identify and assess any abandoned oil and

gas wells within the spacing unit and within one mile of the proposed surface location. This

comprehensive search will ensure all known wells that could be impacted by the specific

proposed operations are evaluated. Locating all other abandoned wells in the state, most of

which pre-date the Department’s Oil, Gas and Solution Mining Law, is not germane to the

proposed action.

Comment 6104:

Part 560.3(a)(9): In addition to identifying any abandoned wells in accordance with this

regulation, revise the regulation to require the applicant to identify the distance from the surface

location of the proposed well to the surface location of any existing well listed in the

Department's Oil & Gas Database or any abandoned well identified by property owners or

tenants within the proposed spacing unit and within one mile of the proposed surface location.

For each well identified, require the following information well name and American Petroleum

Institute number; well type; well status; well orientation; and quantity and type of any

freshwater, brine, oil, or gas encountered during drilling as recorded on the Department's Well

Drilling and Completion Report.

Response 6104:

The Department agrees, and the proposed regulation, now at 560.3(a)(8), provides for the

Department to specify the required information. As explained in the rdSGEIS, the EAF

Addendum would require that an operator submit all of the items listed in this comment.

Comment 6106:

Proposed Part 560.3(a)(13) requires a description of the drilling and hydraulic fracturing engines

to be used, the type of fuel needed for such engines, and a description of planned air emission

control measures. This requirement should be conformed to the final version of the rdSGEIS,

given that the Independent Oil and Gas Association of New York has raised issues concerning

federal preemption and the need for additional mitigation requirements given the aggressive

effort by the United States Environmental Protection Agency to regulate emissions from natural

gas drilling in stimulation activities. Accordingly, Part 560.3(a)(13) should be revised to state: a

description of the drilling and hydraulic fracturing engines to be used, the type of fuel needed for

such engines and a description of any planned air emission control measures.

Response 6106:

The Department agrees. Proposed Part 560.3(a)(12) reflects the comment’s suggestion.

Comment 6107:

Part 560.3(a)(16)(iv) allows too much room for less-than-best-practice by drilling companies and

their subcontractors. Casing seat integrity failures have been implicated in too many cases of

drinking water contamination by gas drillers, in both conventional and unconventional plays. All

precautions, including both casing seat integrity testing and blow-out preventers, should be

required for every well.

Response 6107:

Operators must provide with the application for permit to drill a well subject to Part 560 the

proposed blowout preventer use and test plan for all drilling and completion operations. The

plan must include information on pressure ratings and test pressures of the BOP, related

equipment and casing strings. The Department disagrees with the statement that the proposed

regulation allows for less than best management practices.

Comment 6108:

Proposed Part 560.3(a)(16)(vii), which requires a copy of the operators well control barrier

policy that identifies acceptable barriers to be used during identified operations, is vague and

should be clarified, as industry standard only requires one barrier for testing purposes.

Response 6108:

Part 560.6(c)(3)(i) reflects a conservative approach to well control that the Department has

determined would effectively achieve environmental objectives by requiring the use of at least

two mechanical barriers during the regulated operation.

Comment 6109:

Revise Part 560.3(a) to say the following: 560.3(a)(17): a list of invasive species found at the

well site and measures to prevent the spread of these invasive species including measures being

used to prevent new invasive species being transported into the site; 560.3(a)(20): a

transportation plan indicating the planned route for delivery of raw materials and chemical

additives to the site, the proposed route for transport of waste materials and an estimated number

of truck trips associated with same, providing plans to accommodate the current local truck trips

made by existing businesses.

Response 6109:

Part 560.3(a) has been revised as follows: Part 560.3(a)(16) states, “a list of invasive species

found at the well site and description of the best management practices which will be used for

preventing the spread of these invasive species, including measures being used to prevent new

invasive species from being transported to the site;” Part 560.3(a)(18) states, “a transportation

plan indicating the planned route for delivery of raw materials and chemical additives to the site,

the proposed route for transport of certain waste materials requiring tracking by means of the

department’s Drilling and Production Waste Tracking Form and an estimated number of truck

trips associated with each, and a copy of any road use agreement(s) between the owner or

operator and any municipalities or documentation of the owner’s or operator’s efforts to obtain

such agreements”.

Comment 6110:

Part 560.3(a)(17) provides little substance in protecting biodiversity from oil and gas

development. Almost none of the mitigations proposed by the rdSGEIS are reflected in the new

rules. The requirement of posting best management practices for the identification and control of

invasive species at the drill site is not the same as actually requiring that the driller comply with

those practices.

Response 6110:

Proposed Part 560.3(a)(16) indicates that an operator would need to provide both a list of

invasive species found at the well site and a description of the best management practices which

will be used for preventing the spread of these invasive species. Proposed Part 560.3(c)(3) would

require that an operator provide a map at 1:24,000 scale showing the location and identity of all

occurrences of invasive species within the proposed well site. Permit conditions would require

the operator to fully implement the approved plan.

Comment 6111:

Part 560.3(a)(19): More information should be required relating to reclamation, schedule for

reclamation, etc.

Response 6111:

Proposed Part 560.3(a)(17) would require that an operator provide a partial site reclamation plan

that describes the methods for partially reclaiming the well site following completion, including

a description of best management practices for restoration of native plant cover. Permit

conditions would require the operator to conduct partial reclamation in accordance with the

approved plan.

Comment 6112:

Part 560.3(a)(20): The required transportation plan also should address spill prevention

measures, emergency containment and cleanup procedures, and plans for transportation routes to

avoid sensitive areas such as wetlands, streams, and the habitats of threatened and endangered

species.

Response 6112:

These areas of expertise are not within the purview of a traffic engineer/transportation consultant

who would be preparing transportation management plans. Spill prevention measures are

required as part of the Spill Prevention and Control Plan. Review of an application to drill a well

will address wetlands, streams and habitats work on a case by case basis as part of the

comprehensive review.

Comment 6114:

Part 560.3(b): All surface and subsurface features within and adjacent to the drilling unit should

be required to be mapped.

Response 6114:

The comment is overly broad and does not identify the need for the information to be included

with the plat. Proposed Parts 552.1(b) and 560.3(b) specify the information that an operator

would be required to submit as part of an application package.

Comment 6115:

Part 560.3(b)(2): The topographic map areas should be increased from within 2,640 feet of the

proposed surface location to within one mile of the proposed surface location. The map should

include locations of all aquifers, water wells, stream channels, and other water features. The map

should also include surface geology including faults. Contaminant pathways for transport from

the pad should be identified on the map.

Response 6115:

The mapping requirement in Part 560.3(b)(2) is sufficient to make a decision on whether to issue

a permit. The rdGEIS identifies the appropriate measures to mitigate potential sources of

contamination, including secondary containment where recommended, stormwater management

plans, emergency response plans, and spill control and prevention plans.

Comment 6116:

Part 560.3(c): No substances or chemicals used in the fracturing fluids should be exempt from

disclosure. All products including their chemical and radioactive constituents (not trade names,

but Chemical Abstract Service numbers), volumes, and concentrations and other chemical

additives should be fully disclosed to the Department and the public.

Response 6116:

Part 560.3(c) has been revised to require that, at the time of permit application, all chemical

constituents, be disclosed to the Department by chemical name and CAS Number along with the

proposed actual or maximum concentration of each chemical constituent, in addition to the

product name of each additive proposed for use. Part 560.5(h) requires that the same

information be disclosed to the Department following well completion.

Existing state law, POL 87(2)(d), recognizes the right of persons who submit information to the

Department to request that such information be excepted from public disclosure if the

information qualifies as a trade secret. The Department’s existing Records Access Regulations, 6

NYCRR 616.7, which implement POL 87(2)(d), lay out the process for making such requests, as

well as the Department’s procedure for independently evaluating whether the subject information

qualifies as trade secret. Additive information determined by the Department to be trade secret

could not be disclosed to the public; however, all other additive information would be made

available to the public.

Comment 6117:

Part 560.3(c): In addition to full disclosure to the public regarding the substances and chemicals

intended to be used in each well, those substances and chemicals should be posted online by well

for each individual well at least two months before either drilling (for drilling ingredients) or

fracturing (for fracturing ingredients) begins. This will give nearby landowners a chance to test

their private wells for those chemicals. In addition, all landowners within a one- to two-mile

radius of the well must be notified in writing at least two months ahead with a list of the

chemicals to be used.

Response 6117:

See response to Comment 6116 regarding the hydraulic fracturing fluid additive information

required to be disclosed under Part 560.3(c) and how this information would be handled with

respect to disclosure to the public. As indicated in the rdSGEIS, Material Safety Data Sheets

(MSDSs) would be required to be submitted, as attachments to the EAF Addendum, for each

additive product to be used in the drilling fluid and these MSDSs would be posted on the

Department’s website so that they are available to the public. Since all of the non-trade secret

hydraulic fracturing fluid additive information will available on Department’s website prior to

commencement of a hydraulic fracturing operation and following well completion, the

Department does not find it necessary to provide landowners with individual notification

regarding the chemical constituents to be utilized, as this information will be readily accessible

to all interested individuals/parties.

The requirements for private water well testing imposed upon well operators are addressed by

Part 560.5(d) and the parameters to be tested for are specified in Section 7.1.4.1 of the rdSGEIS.

These parameters, which were recommended by NYSDOH, can be used as indicators of water

quality, and are independent of the specific chemicals used in any given hydraulic fracturing

operation.

Comment 6118:

Part 560.3: Fracturing fluids should be prohibited from containing any substances that are

known carcinogens or endocrine disruptors.

Response 6118:

By implementing the proposed mitigation measures identified in the proposed regulations and

SGEIS, the Department expects that human exposures during routine high-volume hydraulic

fracturing operations would be prevented or reduced below levels of significant health concern.

Therefore, the Department does not agree that it is necessary to prohibit specific substances

based on concerns about health impacts that could only happen if there is an exposure. Proposed

Part 560.3(d) details the hydraulic fracturing fluid information that an operator would need to

disclose for a permit to drill, deepen, plug back or convert a well for high-volume hydraulic

fracturing. See Response to Comment 3438 in Category 90: Part 750, State Pollutant

Discharge Elimination System (SPDES) Permits including permits for High Volume

Hydraulic Fracturing Operations.

Comment 6120:

Part 560.3: In order to reduce the risk of contamination associated with spills or storage failures,

the use of benzene, xylene, formaldehyde, heavy naphtha, diesel fuel, and other petroleum

distillates should be prohibited in fracturing fluids or any other part of the process.

Response 6120:

Some additive products proposed for use in New York contain small amounts of benzene,

toluene, ethylbenzene and/or xylenes. Diesel fuel, however, is not proposed as the carrier fluid

for high-volume hydraulic fracturing in New York and use of diesel fuel for this purpose would

be prohibited by well permits issued under the proposed regulations. See proposed 560.6(c)(24)

and response to Comment 6118.

Comment 6121:

Part 560.3(c)(1)(v): The regulation should provide specific criteria for what constitutes an

acceptable reduction in aquatic toxicity and an acceptable reduction in risk. The regulation also

should identify the type, volume, and concentrations of fracture treatment additives that are

protective of human health and the environment and include a list of prohibited additives. The

list of prohibited fracture treatment additives should apply to all hydraulic fracture treatments,

not just high-volume hydraulic fracturing treatments. The Department should also develop a

process to evaluate newly proposed hydraulic fracturing chemical additives to determine whether

they should be added to the prohibited list. No chemical should be used until the Department

and/or the New York State Department of Health has assessed whether it is protective of human

health and the environment, and has determined whether or not it warrants inclusion on the list of

prohibited hydraulic fracturing chemical additives for New York State.

Response 6121:

The approach taken in the proposed regulations and assumes that hydraulic fracturing fluid

additives, if released into the environment, may pose some potential impact that depends on site-

specific circumstances. Therefore, the requirements contained in the proposed regulations,

Chapter 7 and Appendix 10 of the rdSGEIS, including setbacks, buffers, exclusion areas,

secondary containment requirements, inspection and preventative maintenance protocols, and

well construction requirements, are included as precautionary measures that are intended to

reduce and/or prevent any releases and environmental and human exposures. This approach

addresses a broader range of potential impacts than attempting to apply a toxicity or hazard

characterization to any specific chemicals, since all chemicals are toxic at some exposure level.

Regardless of additive composition, the potential impacts from the chemicals utilized in

hydraulic fracturing are mitigated by the required design and operational controls to prevent

releases and exposures. Therefore, prohibiting specific chemicals or additives is not necessary.

Despite this, proposed Part 560.3(d)(1)(vii), which formerly appeared as Part 560.3(c)(1)(vii),

would require documentation that proposed additives exhibit reduced aquatic toxicity and pose at

least as low a potential risk to water resources and the environment as all known available

alternatives, or documentation that available alternative products are not effective in achieving

the desired results or economically feasible. The Department, however, does not find it

appropriate to specify in regulation an “acceptable reduction in aquatic toxicity” since the

Department will also consider product effectiveness in achieving the desired results, as well as

economic feasibility of use.

Comment 6122:

Add a Part 560.3(c)(1)(vii) that would require an assessment to be conducted of potential adverse

environmental impacts from the proposed fracturing fluid.

Response 6122:

The rdSGEIS assesses the potential adverse environmental impacts from fracturing fluid in

Sections 6.1.3 and 6.1.4. The Department does not agree that requiring additional assessments

for each proposed fracturing fluid would measurably add to the protection of the public health or

the environment.

Comment 6123:

Proposed Part 560.3(c)(1)(v), as well as sections 750-3.4(b)(7) and 750-3.11(e)(1)(i),

contemplate requiring a green fracturing fluid analysis for each well permit. While Industry

supports working toward greener options, as detailed in the Independent Oil and Gas Association

of New York’s Critical Issues Analysis, the proposed analyses are unnecessarily costly and

inefficient. The requirements to conduct a green fracturing fluid analysis for each permit

application, therefore, should be deleted. Alternatively, if an analysis of green fracturing fluid

additives is required, Industry recommends that the Department change Part 560.3(c)(1)(v) to

require the service providers to submit the alternatives analysis to the Department. The service

companies providing high-volume hydraulic fracturing stimulation chemicals and pumping

services to operators are the entities most knowledgeable about the relative environmental

benefits of both existing additive products and new additives. Furthermore, the review of

additives for alternative green chemistry with every new permit application is impractical. When

alternative additives with reduced toxicity are developed, these additives become known

throughout the industry and also by regulators. Since the introduction of new hydraulic fracturing

products is a time-intensive process for service and chemical companies and because operations

tend to use a similar set of products when conditions allow within a play, Industry recommends

that a biennial master chemical review by the high-volume hydraulic fracturing service

companies be instituted rather than a permit-specific review. This chemical review would focus

on the relative toxicity and other environmental attributes of the various additives that are used,

or could be used, by a service company in hydraulically fracturing Marcellus Shale wells or

wells in other shale gas plays. The service company would include in the review any green

products it offers that could be used in shale gas wells. The service company could subsequently

update its master list when it anticipates using a new chemical, or every two years at a minimum.

Each application for permit to drill submitted by an operator would include a permit condition

that the operator must use a service company that has an approved filing on record with the

Department. The service company in turn would have already addressed the relative

environmental attributes of its additive products under its master (biennial) filing to the

Department. Such an approach has several benefits. It places the chemical review responsibility

in the hands of the service companies who provide the fracturing fluids. The service companies

will be the first to know of new chemical availability and, therefore, are best positioned to notify

the Department regarding such products. It will also serve to significantly reduce the review

burden on the Department; there will be only a handful of master review lists requiring approval

(i.e., a list for each service company), rather than adding to the review and approval process for

each. The Department must also consider that green additives may not always be the most

suitable for a particular fracture treatment based on local geology or other conditions. The

universal use of green chemicals which are efficacious but less efficient could result in reduced

well efficiency and less efficient production of the resource. The approach currently

contemplated by the Department appears not to acknowledge the significant steps that have been

taken to improve high-volume hydraulic fracturing chemistry to date (including a trend towards

the overall reduction in the number of chemical additives used in a fracture fluid blend),

particularly as relates to its use in the Marcellus Shale area. Moreover, any final regulation

concerning this topic (and if there is one it should be located only in the mineral regulations)

must consider the efficacy of the proposed fracturing fluid for the target formation and taking

into account site specific considerations, detail how various options should be compared, and

identify who will determine the best alternative.

Response 6123:

The Department recognizes the wide range of products and potential alternatives that may be

used for high-volume hydraulic fracturing, and that research and development associated with

these products (and alternatives) are an ongoing effort by many parties. The Department also

recognizes that improvements have occurred, but because SEQRA requires the maximum

practical mitigation of environmental impacts, the permitting process is designed to ensure that

the best alternatives are used on an ongoing basis. Section 8.2.1.1 of the rdSGEIS describes the

Department’s proposed approach to the evaluation of alternative products, and this approach is

being further evaluated. The Department does not agree, however, with the commenter’s

assertion that the service companies are in all cases the most knowledgeable entities regarding

the environmental fate and transport of the products used in these processes; for example, some

service companies might not employ professional hydrogeologists, environmental toxicologists,

and risk assessment specialists. The Department anticipates that some alternatives evaluations

will be applicable to more than one well permit application and could be done once and

incorporated by reference in subsequent, similar permit applications.

Comment 6124:

Part 560.3: In addition to the list of requirements before gas drilling can commence, the

Department should require testing of the aquifer for hydrocarbons, arsenic, mercury, total

dissolved solids, and radium in an Environmental Laboratory Approval Program-certified

laboratory.

Response 6124:

Proposed Part 560.5(d)(1) indicates that, at a minimum, all residential water wells within 1,000

feet of the well pad would be tested for the parameters specified by the Department, which at a

minimum would include barium, chloride, conductivity, gross alpha/beta, iron, manganese,

dissolved methane and ethane, pH, sodium, static water level (when possible), total dissolved

solids, and volatile organic compounds, specifically BTEX. This list reflects NYSDOH

recommendations; however, the statement that these are minimum requirements would allow the

Department to specify additional parameters it may deem necessary on a site-specific basis.

Comment 6125:

Part 560.3(c)(2) should specify how the Department will maintain the non-disclosed records, and

should be modified so that the exemption from disclosure will not apply in the event of a non-

routine incident or other emergency.

Response 6125:

The Department’s existing Records Access Regulations, specifically 6 NYCRR 616.7(b),

address the Department’s handling of information that is sufficiently justified as trade secret and

applies to how the Department will handle trade secret hydraulic fracturing additive information.

Pursuant to Part 616.7(b), the Director of the Division of Mineral Resources or a designee shall

be responsible for the custody of trade secret records, shall take appropriate measures to

safeguard such records and protect against their unauthorized access, and will use simple and

effective devices to identify and maintain repositories for records containing trade secrets so that

security is maintained. Part 616.7 however, does not provide for the disclosure of trade secret

information by the Department in the event of non-routine incidents or emergencies.

Comment 6126:

Part 560.4(a): Setbacks of 2,000 feet for municipal water supplies is insufficient for many water

resources in the state whose watersheds are significantly larger than the 2,000-foot setback

distance. Taking Owasco Lake as an example, which provides drinking water to the city of

Auburn and surrounding communities, the watershed for Owasco Lake comprises 208 square

miles. A baseline limitation of 2,000 feet from surrounding municipal water supplies is an

insufficient distance to protect the watershed of Owasco Lake, for example, because drilling

from a minimum distance of 2,000 feet from this lake would still clearly fall within the lake's

watershed. The regulation should be revised to prohibit drilling within the watershed of public

waterways. Another approach would be to require an individualized analysis of the impact on the

watersheds of a proposed drilling area.

Response 6126:


Comment 6127:

The Part 560.4 setbacks from aquifers should be revised to require that no well pad may be

located within any known or suspected aquifer or within a one-mile buffer from the boundary of

any aquifer.

Response 6127:

The Department disagrees. Proposed setbacks relative to Primary and Principal Aquifers and

their boundaries are discussed in the rdSGEIS in Sections 7.1.3.5, and 7.1.11.1.

Comment 6128:

Part 560.4 does not provide for the 1,000 foot setback for the tunnels carrying the water from the

source to the New York City locations.

Response 6128:

The complete list of prohibitions based on proximity to water supplies will be included in

proposed Part 750-3.

Comment 6129:

Part 560.4 should include appropriate setbacks for other public and private structures and

facilities such as nuclear power plants, daycare centers, nursing homes, schools, hospitals,

churches, etc.

Response 6129:

The revised Part 560.4 provides for a 500-foot setback from the well pad to any inhabited private

dwelling or place of assembly.

Comment 6130:

The Part 560.4 setbacks should be revised to include the following minimum setbacks: 1,320 feet

for homes, public buildings, and schools; 4,000 feet for private and public wells, primary

aquifers, and other sensitive water resources; and 660 feet for other water resources.

Response 6130:

With the noise and other mitigation measures that would be implemented pursuant to the

rdSGEIS, the Department believes that 500 feet is an appropriate minimum setback for inhabited

dwellings and places of assembly. Beyond 500 feet, noise impacts would be assessed as set forth

in the rdSGEIS. With respect to water resources, see response to Comment 6136.

Comment 6131:

Part 560.4: The floodplain setback should be changed from the 100-year floodplain to the 500-

year floodplain. As well, the regulations should specify approved sources for floodplain

information and location (e.g., Federal Emergency Management Agency maps, United States

Geological Survey, or other sources).

Response 6131:

The Department does not agree. The prohibition within the 100-year floodplain would be

sufficiently protective of potential flooding impacts. FEMA Floodplain Insurance Rate Maps are

one source of information discussed in Section 2.4.9 of the rdSGEIS; this section of the

document also discusses the roles that local governments play in their review of any floodplain

development activity. In addition, proposed Part 560.3 has been revised to provide a notice

period during which local officials could inform the Department of local and site-specific issues.

This would provide an opportunity to mention areas outside the 100-year floodplain that are

known to be susceptible to flooding and where the Department should consider mitigation

measures such as moving or elevating the well pad.

Comment 6132:

Part 560.4: All setback distances should be measured from not only the well pad, but also from

the underground laterals.

Response 6132:


Comment 6133:

Part 560.4 should clarify that setbacks are measured from the edge of the drill site. Wells should

be centered on the well pad and should be set back at least 100 from the pad edge, to maximize

well setbacks from sensitive receptors.

Response 6133:


Comment 6134:

The Part 560.4 setbacks should be reevaluated and revised as a result of a hazard identification

analysis the Department should perform to provide scientific and technical justification for each

setback distance and demonstrate how that distance is protective of the nearby sensitive receptor.

Response 6134:

The Department respectfully does not agree that the setback distances must be reevaluated after

completion of a hazard identification analysis. The sensitivity of a receptor to a given drilling

activity will depend upon many factors. Setbacks were developed by balancing the protection of

the receptor, which is achieved by many measures including setbacks, and the policy in ECL

§23-0301 to allow for the recovery of the natural gas resources and to protect correlative rights.

The magnitude of the setback reflects the magnitude of the potential risk and the potential harm

in the event of a spill. Setbacks that are delineated in the proposed regulations are designed to

ensure that significant adverse environmental impacts are avoided or mitigated to the greatest

extent practical. The Department believes that, with proper planning, a prudent operator can

address these elements in an efficient manner.

Comment 6135:

Part 560.4 should be revised to allow local zoning authorities to establish more protective

setbacks than statewide regulations to address unique and site-specific local concerns and

community characteristics.

Response 6135:

Note that proposed Part 560.3 has been revised to provide a notice period during which local

officials could raise unique and site-specific local concerns and community characteristics. See

also the response to Comment 6131.

Comment 6136:

The Department proposes to codify the setbacks and prohibitions proposed in the rdSGEIS in a

new, proposed Part 560.4. For the reasons detailed in the Independent Oil and Gas Association

(IOGA) of New York's Critical Issues Analysis (Tab 1 to IOGA cover letter) and Comments on

the rdSGEIS (Tab 2), IOGA recommends that many of the setbacks be eliminated or reduced to

the existing setbacks, or setbacks that are consistent with those in place in other neighboring

states. IOGA further recommends that broad waiver provisions be included in the regulations to

allow setbacks to be waived by the Department for good cause shown based upon the application

of superior technology. Finally, for the prohibitions or setbacks that the Department is proposing

to revisit in a given period of time, it would be far better to have those provisions automatically

sunset in the regulations subject to an emergency rulemaking, if warranted, or, alternatively,

unless extended by an order from the Commissioner. This would avoid the need to go through

the rulemaking process a second time to eliminate requirements that are already too restrictive.

The cumulative effect of these prohibitions and setbacks [proposed in Part 560.4] comes at

significant cost to large operators, small operators, landowners, and municipalities. Industry

estimates that the cumulative impact of these prohibitions and setbacks will strand approximately

50% of the acreage that is prospective for shale development in New York State. As a

consequence, operators will lose hundreds of millions of dollars already invested in minerals

leases, landowners will lose millions of dollars in royalties, the state and local governments will

lose significant tax revenue, and very few operators, if any, will be willing to invest their drilling

budgets in New York State. The result will be lost economic opportunity for New York totaling

billions of dollars. Since a number of small businesses are impacted by these requirements, the

Department is mandated by the State Administrative Procedures Act (SAPA) to consider less

costly alternatives. Reduction and/or elimination of these setbacks and the inclusion of automatic

sunset provisions are a legal necessity under the circumstances. At an absolute minimum, all

prohibitions and setbacks including those that disqualify an operator from operating under the

rdSGEIS or the multisector general stormwater permit applicable to high-volume hydraulic

fracturing should be identified in Part 560.4 and not contained in the water regulations (Part

750-3.3) nor the well construction and operation regulations (Part 560.6). Scattering the

prohibitions, setbacks, and disqualifications around in different sections of the regulations

creates regulatory confusion and uncertainty. For example, Part 560.6(b)(1)(ii) regarding the

placement of fueling tanks is confusing and an example of a setback that should be contained in

Part 560.4. There should also be a minimum volume applicable to this requirement and the

requirement should expressly state that it does not apply to portable fuel tanks and tankers that

are brought to the site for fueling purposes. Additionally, 750-3.3 should be moved to 560.4 and

the prohibitions and setbacks therein should have sunset provisions to avoid the need to go

through a rulemaking to eliminate the prohibitions. Accordingly, Part 560.4 should be revised to

state: (a) No well pad or portion of a well pad may be located: (1) closer than 250 feet from a

private water well unless waived by the water well owner; (2) within 4,000 feet of, and including

the, unfiltered surface water supply watersheds; (3) within a 100-year floodplain unless the

operator has adopted a contingency plan to monitor for and react to a flood event; and (4) within

1,000 feet of any public water supply (municipal or otherwise) well or intake in a reservoir,

natural lake or man-made impoundment (except engineered impoundments constructed for fresh

water storage associated with fracturing operations), river or stream. (b) No wellbore shall be

located less than 2,000 feet below the surface and within 1,000 feet of the groundwater bearing

zone unless it is demonstrated that adequate protections exist to prevent the migration of

hydraulic fracturing fluids to the groundwater bearing zone. (c) The department may grant a

waiver from any of the prohibitions, setbacks or restrictions provided herein if the operator

agrees to implement additional safeguards and engineering controls that provide a greater degree

of environmental protection than the standards set forth in this part. (d) The setbacks and

prohibitions detailed herein shall be determined based upon conditions existing at the time of

permit application.

Response 6136:

Setbacks have been proposed in order to conservatively provide a margin of safety should the

operational mitigation measures fail or not be implemented in a particular instance. In most

cases, the setbacks are designed to provide an added level of protection from potential surface

spills from a well pad, and thus most setbacks are measured from the closest edge of the well

pad. Additionally, setbacks were developed by balancing the protection of the water resource,

which is achieved by many measures in addition to setbacks, and the policy in ECL §23-0301 to

allow for the recovery of the natural gas resource and to protect correlative rights.

The proposed siting prohibitions in Part 560 may lead to waste of natural gas if such prohibitions

make it impossible to locate a well pad close enough to the resource to enable efficient

development of the spacing unit. However, for now, the Department expects to implement the

Part 560 prohibitions without discretion and does not have plans to incorporate a provision

allowing variances from the prohibitions proposed in 560.4(a)(3)-(5). Note that proposed Part

560.4 has been revised to permit reasonable well location variances to the setbacks from certain

private water wells, inhabited dwellings and places of assembly where written consent has been

given by potentially affected landowners.

The Department routinely uses setbacks from water resources in many of its programs.

Examples include: siting of wastewater treatment facilities; structures from wetlands; certain

docks, wharfs or moorings; and the application of manure. Setbacks serve as a means of helping

to prevent a spill from reaching and contaminating critical water resources. Depending on the

scope of the setback (the larger the distance the greater the protection), a spill can potentially be

contained, or sufficiently delayed before reaching the water source to reduce the potential

impact. In this regard, setbacks represent an effective risk management tool in the event of a

spill. Setbacks can provide the Department and/or the operator of a well the ability to respond to

a spill. Thus, the magnitude of the setback should also reflect the magnitude of the potential risk

and the potential harm.

The proposed rules have been revised to clarify as follows: Well pads for high-volume hydraulic

fracturing would be prohibited within 2,000 feet of any public (municipal or otherwise) drinking

water supply well, reservoir, natural lake or man-made impoundment. Well pads for high-

volume hydraulic fracturing would also be prohibited within a 100-year floodplain and within a

primary aquifer in addition to a 500-foot buffer from the boundary of a primary aquifer.

Comment 6137:

Part 560.5(a) should specify content requirements for the Emergency Response Plan.

Recommendations are included in the rdSGEIS (Chapter 7.13).

Response 6137:

The Department disagrees, as the Emergency Response Plan (ERP) discussion in Section 7.13 of

the rdSGEIS will convey the essential elements of an ERP, as well as the importance of tailoring

a given ERP to a specific site. It is not intended to provide an all-inclusive list of emergencies

(or other non-routine incidents) and their correlative responses.

Comment 6138:

Part 560.5(a): Three days is not long enough for the Department to be able to review an

Emergency Response Plan (ERP). The ERP should be required to be provided and approved by

local emergency response personnel and the town supervisor before the permit is issued.

Response 6138:

The Department disagrees, as it has broad authority to suspend any permit if warranted, for

reasons including but not limited to an operator’s provision of an ERP that the Department

deems inadequate for the protection of public safety or the environment.

Comment 6139:

Part 560.5(b): In addition to notifying county emergency management offices of the information

and events listed in the regulation, notifications should be made to towns, villages, county health

departments, and residents within a mile of the well.

Response 6139:

The Department has revised proposed 560.3 to require the Department to notify local

governments of all applications for high-volume hydraulic fracturing on new well pads in their

localities, and to notify the public when draft permits on new well pads are available for review.

The Department does not agree that the additional notifications suggested by the commentor are

necessary. Sufficient information will be available on the Department’s website for interested

local agencies and residents to track routine operations. Emergencies and related notifications

will be coordinated by the appropriate agency using established procedures and the required

ERP.

Comment 6140:

Part 560.5(c): Residents living within a mile should be notified within five hours of all incidents

in which any fluids are released to the ground, water, or air.

Response 6140:


Comment 6141:

Part 560.5(c): Non-routine incidents should be required to be posted in the Departments online

Spill Incidents Reports.

Response 6141:

The Department agrees that spills at well sites should be entered into its Spills database;

however, new regulations are not necessary to achieve this. The Department does not agree,

however, that all non-routine incidents should be entered, as spills are just one example of the

types of non-routine incidents that may occur at a well site.

Comment 6142:

Part 560.5(c): Define fishing jobs.

Response 6142:

“Fishing jobs” is a term generally recognized by the industry and does not need to be defined in

regulation.

Comment 6143:

The proposed requirement in Part 560.5(c) addresses when non-routine incidents must be

reported to the Department. The Independent Oil and Gas Association of New York (IOGA)

offers the following comments: The proposed regulation would require incidents to be reported

within two hours. This is too short given the remote nature of drilling operations. IOGA

recommends at least four hours instead. The proposed regulation does not specify how to

document compliance and should be amended to make it clear to the regulated community as to

how compliance will need to be documented. Because pressure variations occur often during

high-volume hydraulic fracturing operations, they should not be included as reportable non-

routine incidents. The long list of non-routine incidents may occur sequentially. The

Department, therefore, should clarify when the proposed two-hour reporting limit starts to run.

The requirement that the operator receive Department approval prior to recommencing hydraulic

fracturing activities in the same well after a suspension in hydraulic fracturing pumping

operations should be deleted. An operator can fix certain pump problems within a few hours and

would need the authority to resume immediately, not after a protracted Department review.

Accordingly, make the following two changes to Part 560.5(c): Change "two hours" to "four

hours" in the first sentence. Add the following sentence after the existing sentence that ends in

"health, safety, welfare, or property of any person": "The first event in a series of related events

shall be considered the reportable event."

Response 6143:

The Department recognizes that some drilling operations occur in remote locations; however, the

remoteness of a given location does not preclude the importance of timely reporting, response,

and remedial efforts. Accordingly, the Department disagrees with the suggestion to change “two

hours” to “four hours” in the first sentence. The Department also disagrees with the suggestion to

delete the requirement of its approval to recommence hydraulic fracturing pumping operations.

Comment 6145:

Part 560.5(d)(1): The regulation needs to specify what reasonable attempts to test wells means.

The regulation also should specify that all wells (not just some wells) are required to be tested in

the 1,000- and 2,000-foot distances of the well pad.

Response 6145:

The proposed regulation has been clarified to refer to all residential water wells, domestic supply

springs and water wells and springs that are used as water supply for livestock or crops. The

Department does not agree that the term “reasonable attempts” needs to be defined.

Comment 6146:

Part 560.5(d)(1): Distances at which water well testing is completed should not be based on

arbitrary distances and instead should be based on the hydrogeology of the area and the potential

for contaminant migration. Distances of 1,000 and 2,000 feet from the well pad are inadequate.

2,500 or 5,000 feet would be better.

Response 6146:



Fracturing Operations. The groundwater monitoring program, referenced in that comment,

must take into account the hydrogeology of the area and the potential for contaminant migration.

Comment 6147:

Part 560.5(d): The Seneca Lake Pure Waters Association recommends that the New York State

Department of Health (NYSDOH) oversee the drinking water testing, to ensure the use of

certified procedures and a scientific, unbiased protocol. The analytes should be selected by the

NYSDOH and tailored to the chemicals expected to be used in the development of the specific

gas well. Water wells should be tested into the future after operations have ceased at the well in

order to evaluate water well contamination over time and help establish responsibility for any

remediation. Such data should be made available to the public. The NYSDOH also should set

up a registry to monitor drinking water supplies.

Response 6147:

Revised proposed 560.5(d) requires that water well testing results be submitted to NYSDOH. As

explained in the rdSGEIS, analysis must be by a DOH ELAP-approved laboratory, including the

use of proper sampling and laboratory protocol, in addition to the use of proper sample

containers, preservation methods, holding times, chain of custody, analytical methods and

laboratory QA/QC. Minimum required analytes are now listed in the proposed regulation.

Comment 6148:

Part 560.5(d): Water wells should be required to be tested by an independent third party that is

not associated with the drilling companies or allowed to serve the driller in other capacities.

Response 6148:


Comment 6149:

Part 560.5(d): The Department should specify the parameters to be tested for water well testing.

At a minimum, they should include hydrocarbons, arsenic, mercury, total dissolved solids,

methane, and radium. They also should be tested for all components of the fracturing fluid

disclosed in the permit application.

Response 6149:

The testing parameters recommended by NYSDOH and made a part of Part 560.5(d) must be

included in any private well sampling that is conducted. The proposed rule has been amended to

include the parameters methane, TDS and Gross alpha/beta. NYSDOH determined that the

specified parameters were sufficient for determining whether a water quality impact may have

occurred. Operators may include additional parameters at their discretion. If a non-routine

incident occurs or a complaint is received that requires further investigation, the chemical

information submitted to the Department with the relevant well permit applications would be

consulted, as appropriate, to determine potential additional analytes.

Comment 6150:

Part 560.5(d)(1): The operator should provide the results of water tests to private water well

owners within two days (not 30 days) of the operators receipt of the results.

Response 6150:

The proposed rule requires that the results of each test be provided to the property owner within

30 days of the operator’s receipt of laboratory results and that the pre-drilling sampling be done

prior to site disturbance. The 30-day time frame is reasonable for the operator to receive the

results from the laboratory and distribute the results.

Comment 6151:

Part 560.5(d)(4): Results of water well testing should be made publically available on a

Department website.

Response 6151:

Any data received by the NYS Department of Health as part of required reporting of the test

results and documentation related to delivery would be available to the public through FOIL.

Data collected regarding the water quality of private wells is generally not made publically

available as part of the protection afforded to maintain the privacy of citizens.

Comment 6152:

Parts 560.5(d)(4) and (e): Testing records should be required to be retained for at least 50 years

to provide protection to homeowners with wells that may not be initially contaminated, but are

eventually contaminated through the migration of pollutants slowly through aquifers. Five years

is an insufficient records retention period.

Response 6152:

The requirement that test records and documentation related to delivery of test results must be

maintained for a period up to and including five years after the well is permanently plugged and

abandoned is consistent with the Department’s record retention policies that are established for

various categories of records.

Comment 6153:

Part 560.5(d): All wells within a five-year transport zone around the proposed well should be

located and included in the testing program. Dedicated monitoring wells also should be

established within this zone and included in the testing program.

Response 6153:

The objective of water well testing is to provide baseline information to aid in the investigation

of complaints from well owners about potential contamination. The distance specified in

regulations (1,000 feet, or 2,000 feet if no available wells within 1,000 feet) is sufficient for this

purpose. As proposed in 750-3, the Department may require a groundwater monitoring program

for a proposed well where high-volume hydraulic fracturing would be used.

Comment 6154:

Part 560.5(e): The results of blowout preventer testing and pressure tests on well casings should

be required to be submitted to the Department for review, not just kept on file with the driller.

Response 6154:

The operator must make the results of a blowout preventer test available to the Department at the

well site in accordance with Part 560.5(e). The Department has the option to require the operator

to provide a copy of the test results should there be any question or doubt regarding

environmental protection or public safety.

Comment 6155:

Part 560.5(e): change the reference to "560.3(a)(17)" to 560.3(a)(16).

Response 6155:

Citations in the revised proposal have been updated.

Comment 6156:

Part 560.5(f): The Drilling and Production Waste Tracking form should be required to be

submitted to the Department, as soon as it is available, for review by the Department, and not

just kept on file with the driller.

Response 6156:

Proposed Part 560.5(f) has been amended to require the operator to make the Drilling and

Production Waste Tracking Form available to the public on the operator’s website within 30 days

of receipt of the waste by the disposal or treatment facility.

Comment 6157:

Part 560.5(f) should require a mandatory monthly online filing of the Drilling and Production

Waste Tracking Form so that it is available to and accessible by the public.

Response 6157:


Comment 6158:

Parts 560.5(f) and (g): The regulations should be more specific regarding the information

required to describe proper disposition of wastes and drilling fluids. It is not sufficient to simply

have a form or record that states where the waste and fluids are sent.

Response 6158:

The Department disagrees with the comment. Prior to permit issuance, planned disposition of

fluids will be reviewed by the Department and no permit will be issued unless and until such

plan is approved. See Part 554.1(1). The Drilling and Production Waste Tracking Form must be

completed and maintained by generators, haulers and receivers of all wastes. For all wastes

other than flowback water that is being recycled, that form must also be posted on the operator’s

website, with the URL posted with the permit. Proposed regulations at 6 NYCRR 750-3 include

requirements that must be met for acceptance of this source of wastewater for disposal by

POTWs and on-site and off-site private wastewater treatment facilities. These requirements

clearly define the measures necessary to accept, treat, and discharge this source of wastewater.

The Department’s water quality review process for SPDES permit issuance includes evaluation

of basin-wide impacts associated with the discharge and is protective of the best usages of the

receiving water.

Comment 6159:

Part 560.5(f): Drilling Production and Waste Tracking Forms should be maintained for at least

50 years. Lawsuits can be protracted and contamination might not be discovered for many years.

Response 6159:

The requirement that the Drilling Production and Waste Tracking Form must be retained for a

period of three years for any waste removed from the well site is consistent with the

Department’s record retention policies that are established for various categories of records.

Lawsuits on issues of possible contamination are outside the scope of the proposed regulations.

Comment 6160:

Proposed Part 560.5(g) [which describes requirements for tracking fluids or other waste

materials moved off-site] needs to be clarified. Specifically, the Independent Oil and Gas

Association of New York recommends that the Department specify how the requirement is met if

the intended destination is a mobile truck or temporary holding facility.

Response 6160:

Proposed Part 560.5(g) refers specifically to wastes moved off site via pipeline or other piping.

For any used drilling mud, flowback water, production brine, or drill cuttings removed from the

site - regardless of the transportation method used - the Department’s Drilling and Production

Waste Tracking Form must be completed and retained in accordance with Proposed Part

560.5(f).

Comment 6161:

Part 560.6(a)(1): Proper siting for access roads should be more clearly specified and should take

into account potential effects on both nearby populations as well as sensitive habitats. For

example, access roads should be at least 1/4 mile from buildings and unleased properties since

spills and trucking accidents are common in such operations. At the same time, roads, staging

and storage areas, and utility corridors should not be situated in areas of sensitive vegetative and

wildlife habitat, especially areas of state- or federally-listed threatened or endangered species.

Response 6161:

Part 560.6(a)(1) has been amended to clarify that any new access road must be located as far as

practical from water resources, inhabited private dwellings and places of assembly. The

Department would consider surrounding land uses when reviewing plans for new roads, as well

as sensitive environmental areas, habitats, streams, and slope, in order to minimize the impacts of

the new road. Best management practices for the control of soil erosion would be required as

conditions of the permit and the HVHF General Permit.

Comment 6162:

Section 560.6(a)(3) concerning the materials permitted for construction of piping, conveyances,

valves and tanks in contact with flowback water is vague. Industry, therefore, seeks clarification

as to what is intended.

Response 6162:

Part 560.6(a)(3) has been amended by the removal of the word “composition”. Piping,

conveyances, valves and tanks in contact with flowback water must be constructed of materials

compatible with flowback water.

Comment 6163:

Part 560.6(a)(4)(ii): It is not clear if the pit sizing takes into account large precipitation events

and if so, what procedures will be in place to monitor and remove or contain excess fluids. This

analysis should be incorporated into the regulations in this section.

Response 6163:

Pits authorized by regulation must be maintained in a leak free condition. The requirement to

maintain two feet of freeboard at all times, including during precipitation events is stated in the

rdSGEIS, Appendix 10 – Supplementary Permit Conditions. It will be the operator’s

responsibility to make any necessary preparations when a storm approaches, and any release

resulting from a failure to do so would constitute a violation and could result in an enforcement

action.

Comment 6164:

Part 560.6(a)(4)(ii) regarding total pit volume needs to be clarified to define what is considered a

tract of land, i.e., well pad or 640-acre spacing unit. In addition, Industry recommends that the

reference to related tracts of land be revised to be adjacent tracts of land. Accordingly, Part

560.6(a)(4)(ii) should be revised to state: total pit volume may not exceed 250,000 gallons, or

500,000 gallons for multiple pits on one tract or adjacent tracts of land under common ownership

or control.

Response 6164:

The Department has clarified Part 560.6(a)(4)(ii) to indicate that total pit volume may not exceed

250,000 gallons, or 500,000 gallons for multiple pits on one tract or an adjacent or related tract

of land under common ownership or control.

Comment 6165:

Part 560.6(a)(4)(ii): The new regulations establish an open pit volume limit of 250,000 gallons

for drill cuttings/fluids or 500,000 gallons for multiple pits on one site. The rdSGEIS estimates

that a 7,000-foot well bore combined with a 4,000-foot lateral will produce 217 cubic yards of

cuttings or 44,000 gallons. This appears to be at the upper limit of what is to be expected for a

single well. If the Department anticipates that this 200,000 gallon overcapacity is to serve

multiple wells on one pad then it is facilitating the long-term and unsafe presence of open pits on

the well pad. Since the new regulations will only allow 45 days of waste storage in the pits, this

overcapacity seems unwarranted unless the Department intends to allow consistent variances to

drillers that exceed the anticipated waste fluid amounts. Section 5.2.3 of the rdSGEIS details the

tanks and recirculation apparatus for drilling muds that suggest all liquids are recycled into the

drilling process and cuttings are separated, so there should not be that much liquid waste in the

reserve pits; certainly not enough to require a 200,000-to-500,000 gallon impoundment. The

Department should reject open pits as a best available technology in favor of closed loop

systems.

Response 6165:

Reserve pits for temporary storage and/or disposal of cuttings will be permitted in certain

circumstances, as explained in the rdSGEIS. The Department will utilize mitigation measures to

address potential significant adverse environmental impacts from any on-site reserve pit. One of

those mitigation measures is to limit pit volumes to 500,000 gallons for multiple pits on one pad.

See also response to Comment 6168.

Comment 6166:

Part 560.6(a)(4): Pits should be required to be fenced and covered to exclude wildlife contact

with drilling fluids, mud, and cuttings.

Response 6166:

Given the temporary nature of drilling, wildlife exposure to reserve pit fluids during drilling

would be limited. Wildlife would not be exposed to flowback water and production brine

because reserve pits are prohibited from containing fracturing fluid, flowback water, or

production brine. The Department, therefore, does not expect any significant adverse impacts to

biota through exposure to pits. In designated Agricultural Districts, the Department would

recommend fencing of sites in active pasture areas to prevent livestock access.

Comment 6167:

Part 560.6(a)(4) should be clarified to specify what materials and fluids may be stored in open

pits. No drilling fluids should be stored in open pits since the Department proposes no standards

for drilling fluids, which can be as toxic as fracturing fluids.

Response 6167:


Comment 6168:

Part 560.6(a)(4): All flowback, wastewater, drilling fluids, drilling muds, and cuttings should be

required to be maintained in a closed-loop steel tank system and not allowed to be placed in open

pits. Closed-loop tank systems are discussed in the rdSGEIS but not in the regulations.

Response 6168:

Part 560.6(c)(27) states that flowback water is prohibited from being directed to or stored in any

on-site pit. A closed-loop tank system must be used to manage drilling fluids and cuttings for

horizontal drilling in the Marcellus Shale unless an acid rock drainage mitigation plan for on-site

burial of cuttings is approved (Part 560.6(c)(7)). Part 560.7(c) requires cuttings contaminated

with oil-based mud or polymer-based with mineral oil lubricant mud to be contained in a closed

loop-system.

Comment 6169:

Part 560.6(b)(1)(i) requires secondary containment for all fueling tanks. Industry recommends

that this be amended to make it specific to storage tanks. Secondary containment around

temporary tanks such as trucks and stimulation equipment is not necessary to protect the

environment.

Response 6169:

The Department disagrees. Though the temporary nature of fueling tanks associated with

drilling and completion activities would make them exempt from the Department’s petroleum

bulk storage regulations and tank registration requirements, any such fueling tanks - regardless of

volume - must satisfy the secondary containment requirements set forth in Section 7.1.3.1 of the

rdSGEIS.

The secondary containment requirement of Part 560.6(b)(1)(i) is not applicable to vehicle fuel

tanks.

Comment 6170:

Part 560.6(b)(1)(ii) imposes, to the extent practicable, a 500-foot setback from perennial or

intermittent streams, storm drains, wetlands, lakes, or ponds for fueling tanks. The requirement is

confusing and includes a vague and undefined practicability standard. Industry recommends that

the Department clarify the requirement and, in doing so, amend it to include a minimum volume

and further expressly state that the requirement does not apply to portable fuel tanks or tankers

that are brought to a site for fueling purposes. Accordingly, Part 560.6(b)(1)(ii) should be

revised to state: to the extent practical, stationary fueling tanks must not be placed within 500

feet of a perennial or intermittent stream, storm drain, wetland, lake or pond.

Response 6170:

The final rule will be amended to remove the words “to the extent practical”. Fueling tanks must

not be placed within 500 feet of a perennial or intermittent stream, storm drain, regulated

wetland, lake or pond. The Department disagrees with the comment that a minimum volume

should be specified in regulation.

Comment 6171:

Part 560.6(b)(2) should be clarified regarding how this will be enforced.

Response 6171:

The Department maintains the right to conduct on-site inspections and respond to citizens’

complaints. Based on the required notifications, Department staff would be aware of a hiatus in

wellsite activities and could initiate a compliance investigation.

Comment 6172:

Part 560.6(c)(2)(i) requires that an operator or operator’s designated representative be present

during all drilling and completion operations when a blowout preventer is installed. This

requirement should be clarified to specify whether this designated representative can be from the

drilling company.

Response 6172:

The Department does not agree that the regulation needs to be more specific. The operator could

designate a drilling crew member as its designated representative as long as he or she has a

current well control certification.

Comment 6173:

Part 560.6(c)(2)(ii): A Department inspector should be on-site to make sure that appropriate

pressure control procedures and equipment are in proper working order and properly installed

and employed while conducting drilling and completion operations.

Response 6173:

A Department inspector will be present for any critical operations that warrant inspection. Part

560.6(c)(2)(i) requires that the operator or its designated representative be certified in well

control and present at the well site when the blowout preventer in installed, tested or in use.

Comment 6174:

Part 560.6(c)(2)(ii) requires that a snubbing unit or coiled tubing unit with a blowout preventer

be used to enter any well with pressure or to drill out one or more solid-core stage plugs.

Industry recommends that this requirement be deleted as unnecessary because a work over rig

with appropriate circulating fluid can handle most interventions.

Response 6174:

The proposed regulation allows an operator with prior Department approval to use equipment

other than a snubbing unit or coiled tubing unit with a blowout preventer.

Comment 6175:

Part 560.6(c)(2): Blowout preventers should always be used.

Response 6175:

The Department agrees that blowout preventers should be used. Proposed 560.6(c)(2)(ii) would

require a blowout preventer and related pressure control equipment to be installed and employed

while conducting drilling and completion operations including tripping, logging, running casing

into the well, and drilling out solid-core stage plugs.

Comment 6176:

Part 560.6(c)(3)(i) requires, at a minimum, two mechanical barriers for use during identified

operations. Industry recommends that this requirement be deleted. Standard industry practice

requires only one barrier for testing purposes.

Response 6176:

Part 560.6(c)(3)(i) reflects a conservative approach to well control that the Department has

determined would effectively achieve environmental objectives by requiring the use of at least

two mechanical barriers during the regulated operations.

Comment 6177:

Part 560.6(c)(4): Drilling down and then placing a casing pipe, but prior to cementing, leaves

the annular space between the casing and the bore wall open. This could allow whatever methane

pockets there may be to flow upwards into shallow groundwater. While methane detection is

already required, a suggestion is to first require a small-diameter bore down to the depth of the

intended first cement seal to monitor for any methane pockets. The small bore, not exceeding

four inches, would minimize upward migration of methane and allow the test bore to be stopped

when methane is detected. The intended first cementing depth would then be adjusted

accordingly.

Response 6177:

The above-mentioned alternative drilling method simply is not practical nor does it provide any

additional environmental protections. Given the short duration between the running and

cementing of casing, the annulus would not be open long enough for groundwater to be

negatively impacted by the presence of methane.

Comment 6178:

Part 560.6(c)(4): Delete "if practical."

Response 6178:

The Department agrees and the proposed regulation has been amended to remove the words “if

practical”.

Comment 6179:

Part 560.6(c)(4): If hydrogen sulfide is encountered, a Department inspector should be required

to be notified.

Response 6179:

Release of hydrogen sulfide during drilling or completion operations would be considered a

reportable non-routine incident. Proposed Part 560.5 regulations require any non-routine

incident to be reported to the Department within two hours of the incident’s known occurrence or

discovery.

Comment 6180:

Part 560.6(c)(4) and (22): The proposed regulations would require the drilling operator for each

well to log the depths and estimated flow rates where inflows of fresh water, brine, oil and/or gas

were encountered or circulation was lost during drilling. The information recorded will depend

to some degree on the skill and attentiveness of the driller, and small inflows could easily be

overlooked. Therefore, geophysical resistivity logs that can distinguish fresh from salty water

should also be run. The information, along with a treatment plan, should be received by the

Department at least three days prior to hydraulic fracturing.

Response 6180:

All information on depths, estimated flow rates where fresh water, brine, oil and/or gas were

encountered or circulation was lost during drilling operations must be included with the

treatment plan. Part 560.6 requires the operator to submit this information to the Department at

least three days prior to commencement of high-volume hydraulic fracturing operations. See

response to comment 6200.

Comment 6181:

Part 560.6(c)(5) should be revised to state: The intentional annular disposal of drill cuttings or

fluid is prohibited.

Response 6181:

The Department does not agree that the regulation should be amended to include the word

“intentional”. Annular disposal is prohibited for operational and environmental reasons relating

to inadvertent injection into zones shallower than the intended injection zone.

Comment 6182:

Part 560.6(c)(7)(ii): Drill cuttings should not be allowed in municipal landfills. They should be

considered to be hazardous waste.

Response 6182:

The Department disagrees with the statement that drill cuttings are hazardous waste; see

response to Comment 3833. In accordance with proposed Part 560.7(c) and (d) drill cuttings

must be disposed off-site or buried on-site in accordance with a Department approved disposal

plan. Any permitted Part 360 solid waste landfill that receives drill cuttings from high-volume

hydraulic fracturing development would be required to operate radiation detection equipment

and to modify its operating manual to include procedures for detecting prohibited radioactive

material, operation and maintenance plans for radiation detectors including standard sensitivity

settings and calibration methods, and response procedures to be implemented if radioactive

waste is detected. These measures have been recommended and are sufficient to ensure that

regulated radioactive waste is not disposed of at any Part 360 landfill. Part 360 landfills are

designed and permitted to prevent leakage, and the Department anticipates sufficient capacity

exists in New York for this waste stream. Therefore, the Department has concluded that Part 360

solid waste landfills constitute the preferred disposal option for drill cuttings that cannot be

buried on-site.

Comment 6183:

Part 560.6(c)(7) should be revised to apply to any shale formations, Marcellus or Utica.

Response 6183:

The Department disagrees, as proposed Part 560.6(c)(7) addresses the use of closed loop tank

systems independent of lithology. As stated in proposed Part 560.6(c)(7)(ii), closed-loop tank

systems would be required to be used for any drilling requiring cuttings to be disposed of off-

site. The requirement to address acid rock drainage for on-site burial of Marcellus cuttings is

based on information provided to the Department regarding Marcellus Shale composition. The

Department does not agree that this information raises concerns about other shale formations.

Comment 6184:

Part 560.6(c)(8): No transfer sites should be allowed because drill cuttings are toxic.

Response 6184:


Comment 6185:

Part 560.6(c)(9): Residents within one mile should be notified at least two months in advance of

the biocides to be used so they can test their private water wells for them.

Response 6185:

The Department disagrees with the comment that residents within one mile of a well pad should

be given two months notice prior to biocides being used. In addition to the parameters specified

by Part 560.5(d)(1) that an operator must sample and test for prior to site disturbance of a new

pad or well spud, residents may test their water wells for the presence of biocides at their

discretion. Mitigation measures provided by Part 560 regulations that are intended to prevent

migration of fluids from the wellbore to private water wells (e.g., casing and cementing

requirements) would act to help prevent microbial transfer from the well.

Comment 6186:

Parts 560.6(c)(10) to (19): The Department needs to provide scientific evidence from

independent researchers not funded by the gas industry that the standards the Department has set

for casing and cementing will prevent contamination of wells and public drinking water sources.

These regulations on casing and cementing are no stronger than those in effect in Pennsylvania,

where wells have failed (e.g., Dimock), and are less stringent than regulations in other areas.

Response 6186:

The well drilling and construction requirements of Part 560 will prevent significant adverse

impacts to drinking water sources. The commenter did not provide scientific evidence or actual

documented events in support of the conclusion that the Department’s rules for casing and

cementing are less stringent and protective than other states, and the Department disagrees with

the commenter’s unsupported conclusion.

Comment 6187:

Part 560.6(c)(10): Cementing creates a fundamental concern. Cement mixed with aggregate

shrinks as it sets and continues to shrink over time. If there are such things as non-shrinking

cement or grout, the regulations should mandate their use. The only specification in the

proposed regulations is that a calculated compressive strength of 500 psi is achieved prior to

disturbing the casing. Every construction project involving concrete requires test cylinders to be

tested for strength. For this critical facet of gas wells, the proposed regulations provide only for a

waiver to allow testing to shorten the wait-on-cement (WOC) 8-hour requirement. The

regulations should specify appropriate sampling and testing of cement over time to ensure that

cement shrinkage is within an acceptable range. If not the well operator should be required to

address the issue of possible methane leakage between strata.

Response 6187:

The commenter is mistaken that cement used in oil and gas well applications contains aggregate.

Oil field cement is thinner than cement or concrete used for construction purposes due to the

requirement that it flow and be pumped under pressure. Other than performing a bench test of the

actual cement batch used to cement the casing, there is no practical way of testing for cement

properties once it has been pumped into the well. Proposed Part 560 regulations require that the

cement used must conform to specifications identified in the permit.

Comment 6188:

Part 560.6(c)(10)(v): The standards should be defined in the regulations.

Response 6188:

The words “industry standards” have been remove from the proposed rule. Proposed Part

560.6(c)(10)(v) has been amended to provide that cement must conform to specifications

identified in the permit to drill.

Comment 6189:

Part 560.6(c)(10)(v) specifies a gas-block additive as a requirement. A gas-block additive should

not be required in the surface string since this string is intended to case off water zones where

deeper strings would have cement in contact with gas bearing zones. Furthermore, the

requirement is too prescriptive. Industry, therefore, recommends that this requirement be deleted.

Accordingly, Part 560.6(c)(10)(v) should be revised to state: cement must conform to industry

standards specified in the permit to drill and the cement slurry must be prepared to minimize its

free water content in accordance with the industry standards and specifications, and contain a

gas-block additive where gas is encountered during the drilling process.

Response 6189:

See response to comment 6188. The proposed rule has been amended to require that the cement

slurry contain a gas-block additive or as approved by the Department, the use of a cement blend

that is functionally equivalent.

Comment 6190:

Part 560.6(c)(10)(x): Cement job logs should be required to be submitted to the Department for

review upon completion, and not just upon request.

Response 6190:

The Department does not agree that it is always necessary to review the casing cement job log.

It would at the Department’s discretion to review the cement job log if information gathered

from the well site indicates the cement bond may not be adequate.

Comment 6191:

Part 560.6(c)(10)(x): The records should be kept and presented on request for 50 years or more

after the last well is plugged.

Response 6191:

The requirement that the operator must provide a copy of the cement bond log to the Department

at any time and including five years after the well is permanently plugged and abandoned is

consistent with the Department’s record retention policies that are established for various

categories of records.

Comment 6192:

The recommendations listed in the Intermediate Casing Analysis Table (Appendix B to the

Harvey Consulting LLC report) should be considered for the rdSGEIS and Part 560. The Harvey


be incorporated: Waiver Provisions, Setting Depth, Protected Water Depth Verification, Cement

Sheath Width, Amount of Cement in Annulus, Excess Cement, Cement Type, Cement Mix

Water Temperature and pH Monitoring, Lost Circulation Control, Spacer Fluids, Hole

Conditioning, Cement Installation and Pump Rate, Rotation and Reciprocation, Centralizers,

Casing Quality, Drilling Mud, Cement Setting Time, Cement Quality Assurance/Quality Control,

Record Keeping, and Additional Casing or Repair.

Response 6192:

Comment noted. The majority of the content of the recommendations listed in the Intermediate

Casing Analysis are addressed in the revised proposed rule. In general, the Department agrees

that the industry best practices referenced in the Harvey Report should be followed. The

Department disagrees with the suggestion that intermediate casing be made mandatory for every

well that will be completed using high-volume hydraulic fracturing as there may be instances

where intermediate casing could be omitted without compromise to environmental protection

and public safety.

Comment 6193:

The recommendations listed in the Production Casing Analysis Table (Appendix C to the Harvey

Consulting LLC report) should be considered for the rdSGEIS and Part 560. The Harvey


be incorporated: Casing Design, Cement Sheath Width, Amount of Cement in Annulus, Excess

Cement Requirements, Cement Type, Cement Mix Water Temperature and pH Monitoring, Lost

Circulation Control, Spacer Fluids, Hole Conditioning, Cement Installation and Pump Rate,

Rotation and Reciprocation, Centralizers, Casing Quality, Casing Thread Compound, Cement

Setting Time, Cement Quality Assurance/Quality Control, Record Keeping, and Additional

Casing or Repair.

Response 6193:

Comment noted. In general, the Department agrees that the industry best practices referenced in

the Harvey Report should be followed. The majority of the content of the recommendations

listed in the Production Casing Analysis is addressed in the revised proposed Rule.

Comment 6194:

The rdSGEIS and Part 560 should require the operator to: (a) Estimate the maximum vertical and

horizontal fracture propagation length for each well and submit technical information (e.g.,

model output) with its application to support its computations. (b) Describe in its post-well

completion report whether the predicted vertical and horizontal fracture propagation lengths

were accurate, or note discrepancies. (c) Certify that the high-volume hydraulic fracture work

was implemented safely and fracture propagations did not intersect protected aquifers or nearby

wells. Additionally, the State should reserve the right, and provide funding, to periodically

review Industry’s models and computations to assess quality and verify this work is being

completed.

Response 6194:

Proposed Part 560 requires that the treatment plan include a hydraulic fracture stimulation model

showing the treatment interval and anticipated pressures and volumes of fluid for pumping the

first stage and a description of the planned treatment interval. Hydraulic fracturing operations

must be immediately suspended if any anomalous pressure and/or flow condition is indicated or

occurring including significant deviation from the treatment model profile.

Comment 6195:

Part 560.6(c)(11): The regulation should specify a maximum time limit for when the cement

should be poured into the well after circulating and conditioning. There is no clear indication on

how long the operator can wait before cementing.

Response 6195:

The Department disagrees with the comment. In the event the Department determines that undue

delay would pose an environmental or safety concern it always has the option to propose a

maximum time limit the hole may be circulated and conditioned prior to running surface casing.

Comment 6196:

Parts 560.6(c)(12) and (14): The regulations require that the Department must be notified prior

to surface casing cementing, prior to intermediate casing cementing, and if the operator wishes to

have the requirement for intermediate casing waived. These requirements for notification imply

that the Department may share in the decisions as to placement of casing and cement. If so, then

require that a copy of the drillers log from land surface to the current well depth be furnished to

the Department before decisions on casing and cementing are made.

Response 6196:

The design of the casing and cementing program is determined by the operator and takes into

account drilling, geologic and well control factors. The program must be in compliance with all

applicable Department regulations before it can be approved by the Department. The

Department does not propose at this time to require the operator to provide a copy of the driller’s

log, but note that the Department can request such log or any other information it deems

necessary in order to make a decision on approving an operator’s proposal.

Comment 6197:

Part 560.6(c)(16): No requests to waive any of the cementing requirements should be granted.

The proposed regulations are inadequate even with the intermediate casing.

Response 6197:

The Department disagrees with the comment that the proposed regulations are inadequate. The

proposed regulation provides for the granting of a waiver to the intermediate casing requirement

when it can be shown that environmental protection and public safety will not be compromised.

Circumstances that may warrant a waiver of the intermediate casing requirement include: deep-

set surface casing; shallow total well depth; and absence of fluid and gas between the surface

casing shoe and the target interval. These are examples of the technical bases which the operator

would have to establish to the reasonable satisfaction of the Department and on which the

requirement for an intermediate casing might be waived.

Comment 6198:

Part 560.6(c)(16) should be revised to require a production casing 500-foot cement overlap into

the intermediate casing, which would be more protective.

Response 6198:

The Department agrees and has amended Part 560.5(c)(16) to require 500 feet of cement above

the intermediate casing seat.

Comment 6199:

Parts 560.6(c)(16), (17), and (18): The regulation needs to be revised to be clear that, if cement

logs indicate incomplete cementing, hydraulic fracturing will be prohibited in that well.

Response 6199:

The Department disagrees with the comment. In the event cement evaluation does not verify the

cement bond is adequate then remedial cementing and/or the installation of an additional

cemented casing may be required before hydraulic fracturing operations can be performed. Part

560.6(c)(25) provides further specificity in that cement bond evaluation must be approved prior

to the commencement of hydraulic fracturing operations.

Comment 6200:

Part 560.6(c)(22): The regulations require the operator to record and report the depths and flow

rates where freshwater, brine, oil, and/or gas were encountered or circulation was lost during

drilling operations. The regulation should be revised to say that the operator should identify

those areas with specific conductivity logging. The regulation also should specify limits or

actions the operator should take if certain flow or losses were recorded, as well as what the

Department will do with this information. The required treatment plan also should be required to

include a profile showing anticipated pressures and volumes of fluid for pumping the first stage.

Response 6200:

The Department has proposed regulations that would require the use of geophysical logging to

determine the base of potable water (Part 560.6(c)(11)(ii)). At this time the Department does not

propose additional regulations that specify what logging tools to use. Part 560.6(c)(22) requires

the treatment plan to include a profile showing anticipated pressures and volumes of fluid for

pumping the first stage.

Comment 6201:

Part 560.6(c)(23): The products used in hydraulic fracturing must be required to be disclosed

publicly and periodic testing of the fluid must be undertaken by a third party to confirm that the

substances in the fluids are the ones listed in the disclosure. As well, if different products are

desired, the permit should be modified.

Response 6201:

See response to Comment 6116 regarding the hydraulic fracturing fluid additive information

required to be disclosed to the Department and the public.

While the Department has the authority to verify the accuracy of the disclosed information at any

time, it does not agree that verification through sampling and chemical analysis is necessary to

ensure no adverse health impacts because the mitigation measures for preventing exposure to

hydraulic fracturing additives are not specific to the chemistry of the additives utilized. The

approach used by the Department in developing the regulations for high-volume hydraulic

fracturing is not specific to the chemistry of the additives utilized. The approach used by the

Department assumes that all hydraulic fracturing additive products, if released into the

environment, pose some potential impact that depends on site-specific circumstances. Therefore,

the mitigation measures proposed in regulations including setbacks, buffers, exclusion areas,

secondary containment requirements, inspection and preventative maintenance protocols, and

well construction requirements, are included as precautionary measures that are intended to

reduce and/or prevent any releases and environmental and human exposures. Regardless of

additive product composition or total hydraulic fracturing fluid composition, the potential

impacts from the chemicals utilized in hydraulic fracturing are mitigated by the required design

and operational controls to prevent releases and exposures.

Proposed 560.6(c)(22) states that fracturing products other than those identified in the well

permit application materials may not be used without specific approval from the Department.

Such approval would require that all relevant information be submitted to the Department for any

new additive product.

Comment 6202:

Part 560.6(c)(24): In place of just eliminating diesel fuel as a carrier fluid or additive for

fracturing fluids, the Department should require that all hydrocarbon fluids used in high-volume

hydraulic fracturing comply with the purity requirements for white mineral oil as specified in 21

CFR 172.878. In addition, these fluids should be tested and found to be below the detection

limits of United States Environmental Protection Agency Method 8260B for benzene, toluene,

ethyl benzene, or xylene(s) (BTEX).

Response 6202:

High-volume hydraulic fracturing is a water-based process, with myriad measures proposed to

prevent releases and exposures. Therefore, the Department does not agree that additional purity

or testing requirements for BTEX are required. See responses to Comments 6118 and 6120.

Comment 6203:

Part 560.6(c)(24): The regulation should be clarified to state that diesel fuel may not be used in

any part of hydraulic fracturing operations, except as a fuel for vehicles. Currently, the

regulation states that diesel fuel may not be used as a primary carrier fluid, but does not clearly

prohibit other uses.

Response 6203:

See responses to Comments 6118, 6120 and 6202.

Comment 5336:

The proposed regulations establishing setback requirements in certain areas are so restrictive and

contradictory as to eliminate logical development at numerous potential wellsites. Unintended

consequences of the setback rulemaking include: increase in investment cost for the operator as

well as impacts for the landowner, mineral owner and community; visual impacts of road and

location due to cut-and-fill on hillsides; increased necessity for road maintenance on hilly county

or town access roads; increased road traffic, tree removal, the amount of earth to be moved and

attendant dust from pad placement on wooded hillsides instead of flat open fields; more required

erosion control on access roads, especially in mud, snow, and ice; greater need for coordinating

complex personnel, equipment, and emergency-response logistics.

Response 5336:

Setbacks that are delineated in the proposed regulations are designed to ensure that significant

adverse environmental impacts are avoided or mitigated to the greatest extent practicable. The

Department believes that, with proper planning, a prudent operator can address these elements in

an efficient manner. The proposed placement of the well pad and access road will be reviewed

by the Department in the application to drill and the resources cited are considered during that

review.

Comment 4481:

6 NYCRR Part 560.6(g)(28): "Gas vented through the flare stack must be ignited whenever

possible." Who determines when it is or is not possible? The regulation needs to define the

situations under which venting versus flaring is justified. Flaring is definitely preferred to

venting in regards to controlling air pollution. If there is no valid reason for the gas to be vented

rather than flared, it should be prohibited.

Response 4481:

Well completion activities include hydraulic fracturing of the well and a flowback period to

clean the well of flowback water and any excess sand (fracturing proppant) that may return out

of the well. Flowback water is routed through separation equipment to separate water, gas, and

sand. Once the flow rate of gas is sufficient to sustain combustion in a flare, the gas is flared

for a short period of time for testing purposes. Existing 556.2(b) already specifies the conditions

under which an operator may flare and the changes proposed to subdivision 556.2(b) will clarify

the procedures for the well operator to obtain approval to flare. The Department agrees that it is

undesirable to allow gas to escape in the air; however, flaring (combustion) of gas produced for a

well is necessary in some circumstances. See also response to Comments 4482, 5979 and 8706.

Comment 4482:

6 NYCRR Part 560.6(c)(29): "A reduced emissions completion, with minimal flaring (if any),

must be performed whenever gas is capable of being transported or marketed by connection of a

sales line and interconnecting gathering line." "Green completion" should be required. Since it is

very unlikely that a high-volume hydraulic fracturing well would not produce enough gas to

warrant transporting it to market, there is no valid reason for a pipeline not to be in place before a

well is allowed to be drilled. This would reduce the amount of venting/flaring necessary for the

well.

Response 4482:

Proposed 560.6(c)(29) requires a reduced emission completion (REC) whenever a gathering line,

sales line and compressor station are available during completion of any high-volume

hydraulically fractured well. Further, an applicant for a well permit would be required to submit

a justification for not using an REC, and the justification would be evaluated by the Department.

Comment 5979:

Flaring of gas is permitted if no gathering line is in place at the time of well completion. This

results in a wasted gas resource as well as unnecessary emissions. The Department should amend

the proposed regulations to require that gathering lines be constructed and ready for gas

collection at the time of the completion of the first well on a well pad.

Response 5979:

Existing 556.2(b) already specifies the conditions under which an operator may flare and the

changes proposed to subdivision 556.2(b) will clarify the procedures for the well operator to

obtain approval to flare. The Department agrees that it is undesirable to allow gas to escape in

the air however, flaring (combustion) of gas produced for a well is necessary in some

circumstances. The Public Service Commission (PSC) has exclusive jurisdiction over the siting,

design, construction, and operation of gathering lines and pipelines.

Comment 8706:

Flaring should be defined as a requirement, rather than an option [for high-volume hydraulic

fracturing].

Response 8706:

Flaring is a requirement when a reduced emissions completion cannot be performed.

Comment 4152:

Open pits for storing fracking waste have not been outlawed!

Response 4152:

Proposed 560.6(c)(27) states that flowback water is prohibited from being directed to or stored in

any on-site pit. In addition, covered watertight steel tanks or covered watertight tanks

constructed of another material approved by the Department are required for flowback handling.

Comment 8588:

The total absence of facilities to process and neutralize used fracking fluids results in the

dangerous practice of simply storing this toxic soup in plastic lined pits at the drill sites. Holding

ponds are not 100% effective. I am certain that the holding ponds will be subject to; perforation,

flood events such as those we saw earlier this year in much of the Marcellus region, and weather

variability associated with global climate change guarantees this. The linings of these ponds are

plastic, temporary, and vulnerable to leakage. They will crack and perforate with freezing and

thawing and be subject to accidents of many kinds (e.g., deer hooves and other natural activities).

The pond contents will surely mingle with groundwater, surface waters, and soil under such

circumstances. The rdSGEIS does not provide adequate protection from overflow of the holding

pools.

Response 8588:

See response to comment 4152.

Comment 9030:

In ECL 23-0301, the Legislature of the State of NY has declared that it is in the public interest to

regulate the development, production and utilization of natural resources of oil and gas in this

state in such a manner as will prevent waste. Yet the SGEIS allows for both venting and flaring,

thus wasting the resource. Wasteful disposal of the gas violates New York State Environmental

Conservation law: 71-1305. "It shall be unlawful for any person to: Waste oil or gas." Until

gathering lines are installed, have the industry store gas on site for immediate use by their newly

required natural-gas-powered drilling equipment, compressor stations and trucks.

Response 9030:

The Department agrees that it is undesirable to allow gas to escape in the air. However, limited

venting and flaring (combustion) of gas produced from a well may be necessary in some

circumstances.

Comment 384:

Flowback fluid regulations and definitions are inadequate; new regulations are required.

Response 384:

The Department believes that the draft regulations will provide adequate oversight and, where

necessary, support enforcement activities.

Comment 9797:

All comments and input on the 2009 dSGEIS and the 2011 rdSGEIS for high-volume hydraulic

fracturing should be taken as applicable comments on the high-volume hydraulic fracturing

regulations. This is necessary in case some issue(s) were omitted, or incompletely or incorrectly

addressed in the high-volume hydraulic fracturing regulations that were commented on by the

public for the SGEIS but were not commented on inadvertently for the regulations. Then there

could be no claims that a specific portion of the regulations were acceptable because no public

comments were received on the particular issue(s).

Response 9797:

The Department disagrees with this statement. There was a separate process for public review

and comment on both the draft SGEIS and proposed regulations.

Comment 10465:

The Proposed Regulations only require "a transportation plan indicating the planned route for

delivery of raw materials and chemical additives to the site, the proposed route for transport of

waste materials and an estimated number of truck trips associated with the same." (See Proposed

Regulation 560.3(a)(20)). This contrasts markedly with the rdSGEIS, which sets forth far more

comprehensive requirements for Transportation Plans: The Department would require, as part of

any permit application, that the applicant submit a transportation plan. The transportation plan

would identify the number of anticipated truck trips to be generated by the proposed activity; the

times of day when trucks are proposed to be operating; the proposed routes for such truck trips;

the locations of, and access to and from, appropriate parking/staging areas; and the ability of the

roadways located on such routes to accommodate such truck traffic (rdSGEIS at 7-136). The

rdSGEIS also details the requirements in connection with Local Road Use Agreements, stating

that "the owner or operator should attempt to obtain a road use agreement with the appropriate

local municipality; if such an agreement cannot be reached, the reason(s) for not obtaining one

must be documented in the Transportation Plan." (Id.) At a minimum, the Proposed Regulations

must be revised to reflect the requirements imposed in the rdSGEIS, including the scope of a

Transportation Plan and information relating to a Local Road Use Agreement. Moreover, the

rdSGEIS appears to leave a loophole for an applicant to avoid Local Road Use Agreements,

stating only that "if such an agreement cannot be reached, the reasons(s) for not obtaining one

must be documented in the applicant's Transportation Plan." (rdSGEIS at 7-138)

Response 10465:

The Department acknowledges that in some cases the rdSGEIS is more detailed than some of the

proposed regulations. This provides flexibility for other approaches to be implemented as

operators and the Department – and in this case, DOT -- gain experience. While the rdSGEIS

reflects those approaches that the Department has determined would effectively achieve an

environmental objective, there may be other ways to accomplish the same thing that exist now or

that will be developed as technology advances. The Department always has the option to

propose additional regulations should a specific approach to a given objective become

standardized and also be deemed the only acceptable alternative. The Department is working

closely with DOT to ensure permits are not issued without transportation plans in place that

address any and all legitimate concerns.

Comment 4479:

Cortland County Health Department support the requirements in Part 560 that flowback water

and production brine not be "directed to or stored in any on-site pit." However, other sections of

the regulations (e.g., 553.1 (6)) refer to the disposal of pit liners; 560.7 (a) refers to fluids being

removed from pits). This makes the issue of pits unclear. The use of pits (other than for water

storage) should be absolutely forbidden. Pits typically leak, they can overflow during times of

heavy rains (an increasingly frequent occurrence in New York), and they contribute greatly to

the amount of air pollution.

Response 4479:

Comment noted in support of the requirements that flowback water and production brine not be

directed to or stored in on-site pits. These requirements in Part 560 pertain to flowback water

and production brine associated with high-volume hydraulic fracturing. The pits referenced by

560.7(a) are reserve pits, which store drilling fluids and cuttings when closed-loop drilling is not

required. Use of these pits is limited to drilling that does not use oil-based drilling muds, or

polymer-based muds with mineral oil lubricant, and to drilling that does not require an acid-rock

mitigation plan. Reserve pits at wells permitted and drilled under Part 560 would be subject to

the requirements of proposed 560.6(a)(4), including enhanced construction and maintenance

specifications for pits used for more than one well. There is no 553.1(6) in the proposed

regulations; the word “liner” does not appear outside of Part 560.

90: Part 750, State Pollutant Discharge Elimination System (SPDES) Permits including

permits for High Volume Hydraulic Fracturing Operations

Comment 2451:

Section 750-3.21 reads (in part) (2) Construction activities related to high-volume hydraulic

fracturing (HVHF) operations that: (i) are tributary to waters of the state classified as AA or AA-

s; and (ii) which disturb land with no existing impervious cover; and (iii) which are undertaken

on land with a Soil Slope Phase that is identified as an E or F, or the map unit name is inclusive

of 25% or greater slope, on the United States Department of Agriculture (USDA) Soil Survey for

the surface area where the disturbance will occur. It is our assumption that the proposed

regulations are stating, and, if that assumption is incorrect, our assertion that they should state,

that the HVHF State Pollutant Discharge Elimination System general permit is not authorized

when any one of these conditions are present. Thus, the highlighted "and"s should be "or"s.

Response 2451:

The “and”s in the draft regulations at 6 NYCRR 750-3 are correct, and are consistent with the

SPDES General Permit for Stormwater Discharges from Construction Activities (GP-0-10-001),

which served as the basis for the requirements in the draft HVHF GP and 2011 draft and the

revised regulations at 6 NYCRR 750-3. High-volume hydraulic fracturing is ineligible for

coverage under the draft HVHF GP where all three of the following are present: discharges from

construction activities are tributary to waters of the state classified as AA or AA-s; disturb land

with no existing impervious cover; and where the Soil Slope Phase is identified as E or F and the

map unit name is inclusive of 25% or greater slope on the USDA Soil Survey for the surface area

where the disturbance will occur. The draft HVHF GP also requires the minimization of the

disturbance of steep slopes.

Comment 2453:

Section 750.3.21.f.4 - All proposed zones are too low, by a factor of 10x. This is not a mature

technology. The record shows that spills, operator errors, storm water flow, impound failures

have caused significant environmental damage, with particular impact on drinking water. Some

of these violations have caused permanent degradation of water sources. We need larger buffer

zones until the methodology and operation proves itself reliable and safe. Then, and only then,

the permitting process can gradually reduce those buffer zones.

Response 2453:

The revised regulations, as well as mitigation measures described in the 1992 GEIS and 2011

rdSGEIS, include a broad array of protective measures for water resources. Changes in the

setbacks can be found in the revised regulations at 6 NYCRR 750-3.3 (prohibitions) and 750-

3.11 (ineligible for coverage under a stormwater general permit for HVHF operations, but where

an individual SPDES permit and site-specific SEQRA review are required).

In most cases, the setbacks are designed to provide an added level of protection for surface spills

from a well pad, and thus as related to water resources, setbacks are measured from the closest

edge of the well pad. Additionally, setbacks were developed by balancing the protection of the

water resource, which is achieved by many measures in addition to setbacks, and the policy in

ECL §23 -0301 to allow for the recovery of the natural gas resource and to protect correlative

rights. In this regard, setbacks represent an effective risk management tool in the event of a spill.

Setbacks can provide the Department and/or the operator of a well the ability to respond to a

spill. Thus, the magnitude of the setback should also reflect the magnitude of the potential risk

and the potential harm. Consideration in setting the setbacks was given to the designated use of

the water resource, such as drinking water supply (and in such cases, population served).

In addition to the mitigation measures identified to prevent spills and potential improper runoff

of wastewater, the imposition of a range of setbacks - depending on the nature of the water

resource – should be implemented to conservatively add an additional layer of protection to these

water resources from significant adverse impacts from potential surface spills or other releases

because such setbacks are a tool to prevent a spill from reaching and contaminating critical water

resources. This broad range of protective measures, both spill prevention and the setbacks to

ensure that any spills that do occur do not contaminate critical resources, taken together, provide

an enhanced level of mitigation to prevent potential significant adverse impacts to water

resources.

The revised regulations at 6 NYCRR 750-3 and the draft HVHF GP propose measures to prevent

spills and releases. Specific BMPs are required for all aspects of high-volume hydraulic

fracturing operations (e.g., pit construction and liner specifications; closed-loop systems in

certain instances; flowback water to be stored on-site in covered, water-tight tanks; secondary

containment for all hazardous substances at the well site, as well as for flowback and piping of

wastewater; appropriate pressure-control procedures and equipment; peripheral berm required

for the entire well site as a secondary measure for containing any spills and releases; requirement

of emergency and spill response plans). In addition to the BMPs, setbacks and other regulatory

requirements/controls found in the draft and revised 6 NYCRR Parts 550-559 and draft and

revised Part 560, as well as additional mitigation measures required under the 1992 GEIS and

proposed in Chapter 7 of the 2011 rdSEGIS and the requirements listed in Appendix 10 of that

document, provide additional protections to ensure the environment is protected.

Comment 3014:

The proposed high-volume hydraulic fracturing regulations include both Mineral Resources

regulations (6 NYCRR Parts 550-556 and 560) and State Pollutant Discharge Elimination

System (SPDES) regulations (6 NYCRR Part 750). In promulgating both Mineral Resources

regulations and SPDES regulations, the Department has created needless and irrational

duplication in the permitting process. The areas of overlap include: Setbacks - 560.4(a) is the

same as 750-3.3(b);Chemical disclosure - 560.3(c) is the same as 750-3.11(e)(1)(ii), 750-

3.12(b)(4) (6), and 750-3.13(e);Water well testing - 560.5(d) is the same as 750-3.13(h) and

(i);Closed-loop tank system requirement - 560.6(c)(7) is the same as 750-3.4(b)(2) and 750-

3.11(h);Prohibition of waste fluid storage in a pit or impoundment - 560.6(c)(27) and 560.7(g)

are the same as 750-3.4(b)(3) and 750-3.11(i); Testing requirements related to waste fluids -

560.7(f) is the same as 750-3.11(i); 45-day removal requirement for waste fluids - 560.7(a) is the

same as 750-3.4(b)(5); Requirement to develop a fluid disposal plan - 554.1(c)(1) is the same as

750-3.12(b); Pit requirements - 560.6(a)(4) is the same as 750-3.4(b)(4); Secondary containment

- 560.6(c)(26)(i) is the same as 750-3.11(e)(1)(v); Record keeping waste fluids - 560.5(f) and (g)

are the same as 750-3.13(f) and (g); Record keeping miscellaneous - 560.6(c)(26)(viii) is the

same as 750-3.13(b) - (e); Definitions - 560.2 is the same as 750-3.2. These duplications are also

detailed in Appendix A (page 25 of 37) of the comment. The Department should eliminate the

duplicative language from the SPDES regulations, or eliminate the new high-volume hydraulic

fracturing-specific SPDES regulations altogether.

Response 3014:

The draft regulations at 6 NYCRR 750-3 are for SPDES permitting, not gas well permitting.

Duplication and consistency have been addressed in the revised regulations, including cross-

references to 6 NYCRR Parts 550-556 and 560, where appropriate.

Comment 3436:

6 NYCRR 750.3-2(b)(23), this definition of high-volume hydraulic fracturing should be

consistent with the definition contained in 560.3(b). The definition should be revised so that it

only applies if over 300,000 gallons of fresh water is used, and should not be cumulative.

Response 3436:

The definition of “high-volume hydraulic fracturing” has been revised in 750-3 and is also now

consistent with the definition in the revised 6 NYCRR Part 560. The revised definition is as

follows: “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 account the sum of all water-based fluids,

including fresh water and recycled flowback water, used in all HVHF stages.”

Comment 3437:

6 NYCRR 750.3-2(b)(38), this definition of product should be consistent with the definition

contained in 560.3(b).

Response 3437:

The definitions in the draft regulations at 6 NYCRR 750-3 and the definitions in draft regulations

at 6 NYCRR Part 560 have been changed in the revised regulations for consistency.

Comment 3438:

6 NYCRR 750.3-4(b)(7) and (8), these two sections are duplicative and should be consolidated

into one section. Halliburton Energy Services, Inc. (HESI) suggests allowing the use of its

Chemistry Scoring Index to meet this requirement.

Response 3438:

The draft regulations at 6 NYCRR 750-3.4 have been revised and re-located. The revised

regulations at 6 NYCRR 750-3 state “[t]he owner or operator’s alternative analysis must be in

accordance with subparagraph 560.3(d)(1)(vii) of this Title, as adopted on XX, 20XX. This

includes documentation to the department’s satisfaction, utilizing existing data and studies, that

proposed chemical additives exhibit reduced aquatic toxicity and pose at least as low a potential

risk to water resources and the environment as all known available alternatives; or

documentation, to the Department’s satisfaction, that available alternative products are not

effective in achieving the desired results or economically feasible. The owner or operator must

use the proposed alternatives that satisfy the foregoing requirements.” The Department will

provide further guidance regarding the specifics of the alternatives analysis.

However, there are two concepts in these sections-one mandates the alternatives analysis and the

other mandates the use of less toxic alternatives. Environmentally-friendly alternatives, and the

evaluation and use, if feasible, of less toxic alternatives is proposed to be required for each well

permit. HESI’s proposed CSI was reviewed by several Divisions within the Department and

DOH’s Bureau of Toxic Substance Assessment. Development of an objective scoring system

that would fairly evaluate, compare and rank products that are each composed of multiple

chemicals is a complex exercise including both product performance considerations and relative

risks associated with various site-specific scenarios such as depth of fracturing, surface site

characteristics and proximity to water bodies or significant habitats. The requirement to evaluate

and use less toxic alternatives achieves the same objective. Upon review, the Department has

determined that adoption of HESI’s proposed CSI as part of the well permitting process would

not be feasible or appropriate at this time.

Comment 3439:

6 NYCRR 750.3-11(e)(1)(i), Halliburton Energy Services, Inc. (HESI) suggests allowing the use

of its Chemistry Scoring Index to meet this requirement.

Response 3439:


Comment 3440:

6 NYCRR 750.3-11(e)(1)(ii), the language used in this regulation should be clarified to only

apply to the chemical additives, by product name, and not the individual chemical constituents.

Response 3440:

The revised regulations at 6 NYCRR 750-3 continue to require that, at the well site, the owner or

operator must maintain a list of the chemical additives used on the well site.

Comment 3441:

6 NYCRR 750.3-12(b), Contents of Fluid Disposal Plan, requiring this level of disclosure at the

permit application stage is unwarranted, because the precise additives to be used may change

between the time the permit application is submitted, and the time of the actual hydraulic

fracturing. Therefore, what is submitted with this application will be subject to change. The

Department should provide a seamless process for changing proposed additives. Moreover, there

is no explicit provision in these sections for protection of proprietary confidential business

information. The Department should specifically acknowledge that confidential treatment will be

accorded to proprietary information, and that such proprietary information need only disclosed to

the Department.

Response 3441:

The revised regulations at 6 NYCRR 750-3 require that the owner or operator must have an

approvable plan, which identifies the ultimate disposition of wastewater from high-volume

hydraulic fracturing (Fluid Disposal Plan), in accordance with the requirements set forth in

revised 6 NYCRR 554.1(c)(1), and ensures compliance with any other law or regulation. An

approvable Fluid Disposal Plan must also contain an acceptable contingency plan for disposition

or disposal of such fluids that must be implemented when the primary plan is unsafe or

impracticable at the time of disposition or disposal. The Fluid Disposal Plan must be modified to

cover high-volume hydraulic fracturing wastewater from wells not originally identified.

Specifically, the revised regulations at 6 NYCRR 750-3 state “[t]he owner or operator must

maintain a Fluid Disposal Plan, as required by 750-3.6(d) of this Part, and any modifications to

that Fluid Disposal Plan, including modifications that cover high-volume hydraulic fracturing

wastewater from wells not originally identified.” The Fluid Disposal Plan would be available to

the public, subject to the limitations of the Freedom of Information Law. Disclosure of chemical

additives is otherwise required by revised regulations at 6 NYCRR 750-3.7(k)(1) and referenced

revised 6 NYCRR 560.3(d).

Comment 3443:

6 NYCRR 750.3-12(b)(4), this provision requires disclosure of each chemical in the Fluid

Disposal Plan. This is burdensome, unwarranted and inconsistent with the requirements

contained in the Division of Mineral Resources regulations at 560.3(c). The language should be

changed to be consistent with 560.3(c)(1)(i) through (iv).

Response 3443:

See Response to Comment 3441.

Comment 3444:

6 NYCRR 750.3-12(b)(6), this provision requires that the exact chemical composition of any

additional additives which have not yet been proposed for use before the Department be set forth

in the Fluid Disposal Plan. This provision appears to suggest that the precise formula of new

additives be provided to the Department, and does not make any provision for protection of

confidential business or trade secret information. For reasons set forth in detail in its referenced

comments to the rdSGEIS, Halliburton Energy Services, Inc. (HESI) objects to any requirement

to submit the precise chemical formulae for its additives. Furthermore, this section needs to

acknowledge that such information may be treated as confidential business or trade secret

information, and may be submitted separately by the service company to the Department rather

than exclusively by the operator as currently stated. As discussed in HESIs comments on the

rdSGEIS, because this information is highly valuable intellectual property, HESI does not

disclose this information to its customers/operators.

Response 3444:


Comment 3445:

6 NYCRR Section 750.3-12(d)(1)(vi)(c)1, Headworks Analysis Requirements, the disclosure of

the constituents and formulae for hydraulic fracturing additives is not scientifically required in

order to perform the headworks analysis. Furthermore, this provision does not contain any

provision for treatment of the chemical information used in the additives as confidential business

information. This provision should be clarified to specify that confidential business information

treatment may be warranted. In addition, since the headworks analysis also requires an assay of

the concentration of high-volume hydraulic fracturing chemicals present, disclosure of the

chemicals used in the additives is unnecessary to perform the headworks analysis.

Response 3445:

The information submitted to the Department as part of a headworks analysis would be available

to the public, subject to the limitations of the Freedom of Information Law. For each identified

source of flowback water or production brine, the revised regulations at 6 NYCRR 750-3 require

a representative assay of the concentrations of chemical constituents present, as well as other

constituents that may be present. Additionally, while the chemical additives (referred to in the

comment as hydraulic fracturing fluid additives) may not on their own cause an upset, their

presence must be evaluated in conjunction with the other contaminants present in this source of

wastewater. This evaluation is necessary to determine whether the contaminants are adequately

treated and not passing through the treatment system without treatment, as well as to evaluate the

potential toxicological effects on the receiving water.

Comment 3447:

6 NYCRR 750.3-13(e), Storm Water Pollution Prevention Plan (SWPPP) requirements, this

provision requires that SWPPPs contain a provision to maintain records of chemicals/additives

used, and explicitly acknowledges that the chemicals in the additives used may be excluded from

the records if the chemicals are entitled to treatment as confidential business information. This

language should be incorporated into the sections discussed above. This section should be

revised so that the SWPPP need only include provisions that records be maintained on the

additives by product name, with the Material Safety Data Sheets (MSDSs) for such additives,

and not the individual chemicals themselves. The use of the phrase chemicals/additives is not

defined, and is confusing.

Response 3447:

See Response to Comment 3440. The information would be available to the public, subject to

the limitations of the Freedom of Information Law.

Comment 3781:

6 NYCRR 750-3.12(b) spells out the required components of a hydraulic fracturing fluid

disposal plan that includes requirements for certification by a disposal facility that available

capacity exists for the disposal of wastewaters over the life of the well and identifies a backup

disposal location with sufficient capacity. However, the proposed regulations continue to allow

disposing hydraulic fracturing wastewaters at publicly owned treatment works (POTWs). High-

volume hydraulic fracturing waste should not be treated at POTWs.

Response 3781:

See Response to Comment 3441. POTWs may accept high-volume hydraulic fracturing

wastewater so long as the POTW is in compliance with the applicable regulations, which

includes obtaining any necessary approvals and permits. The revised regulations at 6 NYCRR

750-3 include requirements that must be met for acceptance of this source of wastewater for

disposal at POTWs. The Department’s water quality review process for SPDES permit issuance

includes evaluation of basin-wide impacts associated with the discharge and is protective of the

best usages of the receiving water. Approval to accept high-volume hydraulic fracturing

wastewater would only be issued to a POTW following EPA and DEC’s review and approval of

the facility’s application to accept the wastewater. The POTW must have an EPA or DEC-

approved pretreatment program prior to applying to accept high-volume hydraulic fracturing

wastewater. Pursuant to the General Pretreatment Regulations, and before the POTW is

permitted to accept a new waste stream, the POTW must conduct a headworks analysis and

submit this analysis for Department and EPA approval. The headworks analysis evaluates the

pollutants present in the wastewater against the capabilities of the treatment system and assesses

any potential adverse impacts to a treatment system process. If the headwork analysis indicates

that the treatment process could be adversely impacted by the pollutants present in the high-

volume hydraulic fracturing wastewater, that the high-volume hydraulic fracturing wastewater

would not comply with the pass through and interference provisions in 40 CFR Part 403.5, or

that the high-volume hydraulic fracturing wastewater may cause a water quality violation in the

receiving waterbody, additional treatment would be required to reduce the pollutants of concern

to a safe level before the POTW would be permitted to accept the wastewater. Also, the water

quality-based effluent limitations in any SPDES permit are calculated using the critical low flow

of the receiving water to assure that water quality standards and guidance values are met at all

times during the year. All SPDES permits require periodic monitoring to ensure compliance

with applicable limits to ensure that water quality standards are met. Discharge limitations in

SPDES permits are developed based upon the more stringent of aquatic, water source, or

technology standards and are set at levels to ensure that the discharges do not impair water

quality standards, including those protective of wildlife and aquatic habitat.

Comment 3784:

6 NYCRR 750-3.13(h), which requires baseline testing and ongoing monitoring provisions

should be strengthened to provide better protections for all neighbors of hydraulic fracturing

operations and the possibility of swifter remediation attempts should contamination occur.

Consider the following: 1) The proposed regulation would require an operator sample residential

water wells within 1,000 feet of the well pad (within 2,000 feet if no well is found within 1,000

feet) and provide results to the well owner. There is no reason that this requirement be restricted

to residential wells. The aim of the requirement seems to be to assign or remove responsibility if

well water nearby a high-volume hydraulic fracturing operation becomes polluted; baseline

testing is supported for this reason. Whether a well within 1,000 or 2,000 feet supplies a

residence, a commercial operation or an industrial operation, high-volume hydraulic fracturing

owners/operators should be responsible for baseline testing. 2) Regulations should establish

minimum contaminate parameters for which owners/operators would be required to test. 3) A

minimum monitoring schedule, with additional monitoring required at the discretion of the

Department should be included in final regulations. The schedule should include baseline testing

prior to site disturbance at the first well on the pad, and prior to drilling commencement at

additional wells on multi-well pads; sampling and analysis three months after reaching total

measured depth (TMD) at any well on the pad if there is a hiatus of longer than three months

between reaching TMD and any other milestone on the well pad that would require sampling and

analysis; sampling and analysis three months, six months, and one year after hydraulic fracturing

operations at each well on the pad (with the ability for the Department to stipulate that for multi-

well pads where drilling and hydraulic fracturing activity is continuous, to the extent that water

well sampling and analysis according to the schedule would occur more often than every three

months, to simplify the protocol so that sampling and analysis occurs at three month intervals)

and sampling annually every year that the well is producing. While some of the above

monitoring schedule is proposed in the rdSGEIS, Section 7.1.4.1, minimum standards and annual

testing should be mandated to ensure the integrity of the well construction and casing. 4) The

proposed regulations would require that the operator maintain the results of the water well tests.

The Department is urged to make these results publicly available so that New Yorkers may track

pollution caused by high-volume hydraulic fracturing and have a better understanding of water

quality in areas where high-volume hydraulic fracturing is occurring, more generally. To this

end, the agency could either maintain the results itself or establish a mechanism by which the

public could petition the Department to obtain the results on its behalf. The proposed 6 NYCRR

560.5 establishes water well testing as part of the high-volume hydraulic fracturing requirements

separate from, but parallel to the State Pollutant Discharge Elimination System (SPDES) permit

regulations. The comments made above in reference to the monitoring requirements in the

proposed SPDES regulations apply here as well.

Response 3784:

In addition to the requirement that owner or operator conduct residential water well testing, in

accordance with the requirements of revised 6 NYCRR 560.5(d), the revised regulations at 6

NYCRR 750-3 require an approvable groundwater monitoring program be developed and

implemented. The 2011 rdSGEIS and the revised regulations at 6 NYCRR 560.5(d) include

indicator parameters for private water well testing. Should there be an identified impact from

that monitoring, additional monitoring may be required and/or analytes may be tested for.

Comment 3785:

Environmental Advocates supports proposed 6 NYCRR 750-3.21, the regulations determining

what may or may not be covered under the State Pollutant Discharge Elimination System

(SPDES) General Permit, with the exception of 6 NYCRR 750-3.21(f)(4). It is not enough to

require an individual SPDES permit for high-volume hydraulic fracturing operations within a

principal aquifer. High-volume hydraulic fracturing operations should not be permitted over

principal aquifers.

Response 3785:

There are specific factors that support the fact that high-volume hydraulic fracturing in, or within

500 feet of, a Principal Aquifer, may not be covered by a general SPDES permit, instead of being

prohibited. Primary water supply aquifers are defined as highly productive aquifers presently

being utilized as sources of water supply by major municipal water supply systems, and as such,

high-volume hydraulic fracturing is prohibited in those aquifers. Principal Aquifers are aquifers

known to be highly productive or whose geology suggests abundant potential water supply, but

which are not intensively used as sources of water supply by major municipal systems at the

present time. Therefore, in general, Principal Aquifers do not serve major municipal water

supply systems and fewer individuals compared to Primary Aquifers. Accordingly, rather than

applying an absolute 500-foot prohibition, as the case with Primary Aquifers, high-volume

hydraulic fracturing within 500 feet of a Principal Aquifer is not covered by a general SPDES

permit. An application to construct a well pad in a Principal Aquifer or within 500 feet of the

boundary of the aquifer would require an individual stormwater permit, subject to public notice

and comment. As part of the individual permit review process (and the associated site-specific

SEQRA review), the appropriateness of placing a well pad in the proposed location would be

evaluated and may or may not be permitted based on that site-specific review. If permitted,

enhanced mitigation measures would be tailored to the specific application. Among other things,

the Department will consider the following factors when considering an application to construct

a well pad in a Principal Aquifer or within 500 feet of the boundary of the aquifer:

topographical features, such as depressions and overall slope of the land; distance to drinking

water supplies and population served; or other uses of the aquifer.

Comment 3838:

Refer to definition (49) in 6 NYCRR 750-3.2, the word "lake" should be inserted in the last line

of the definition of "unfiltered surface water supplies" to read "... Skaneateles Lake Drinking

Water Supply Watershed." Elsewhere in the documents, the term "Syracuse Watersheds" should

appear as "Skaneateles Lake Watershed," to avoid confusion with watersheds in the City of

Syracuse.

Response 3838:

The draft regulations at 6 NYCRR 750-3 have been revised to refer to this unfiltered drinking

water supply as follows: “Syracuse Drinking Water Supply Watershed.”

Comment 3855:

Proposed regulation 750-3.3 (b), and 750-3.21 (f) (4) a High-Volume Hydraulic Fracturing State

Pollutant Discharge Elimination System (SPDES) general permit should not authorize operations

sited within the following buffers: (1) closer than 1,000 feet from a private water well unless

waived by the water well owner; (2) within a the geometric boundary of a primary aquifer and a

2,000-foot buffer from the boundary of a primary aquifer or surface water divide for the aquifer,

whichever is closer; (3) within a 100-year floodplain and a 500 foot buffer of the 100-year

floodplain; (4) within 500 feet of a wetland; (5) within 2,000 feet of any public water supply

(municipal or otherwise) well, reservoir, natural lake or man-made impoundment (except


operations), and river or stream intake; (6) within 2,500 feet of any faults or Fracture

Intensification Domains that are mapped within 1,000 feet of any public water supply (municipal

or otherwise) well, reservoir, natural lake or man-made impoundment (except engineered

impoundments constructed for fresh water storage associated with fracturing operations), and

river or stream intake; (7) within 1,000 feet of any active or abandoned salt mine; (8) below a

Finger Lake or dry Finger Lake valley and within 500 feet of the Finger Lake; and (9) within 500

feet of a perennial stream.

Response 3855:

See Response to Comment 2453. With respect to water resources, the draft regulations at 6

NYCRR recite where high-volume hydraulic fracturing is prohibited (750-3.3), and where the

activity does not qualify for coverage under the stormwater general permit for HVHF operations

(750-3.11).

Comment 3858:

Proposed regulation 750-3.12 (d) (1) (vi) (b) references Division of Water Guidance Document

1.3.8.1, Guidance for Acceptance of High-Volume Hydraulic Fracturing Wastewater by

Publically Owned Treatment Works. The Department website was searched and while the 1994

edition of 1.3.8 was available, it does not seem applicable. A call was placed to Division of

Water and staff there thought there must be a typographical error because there was no guidance

document with the number 1.3.8.1. If a new document is to be created, it should be available for

review with the rest of the proposed regulations.

Response 3858:

References to guidance documents have been removed from the revised regulations at 6 NYCRR

750-3.

Comment 3894:

The following definition should be added for wetlands under 750-1.2(a)(99): Wetlands means

any area regulated pursuant to Article 24 of the Environmental Conservation Law; and federally

regulated wetlands, which are further defined as areas included under the definition of "waters of

the United States" at 33 CFR 328.3(b), which defines the term "wetlands" to mean "those areas

that are inundated or saturated by surface or ground water at a frequency and duration sufficient

to support, and that under normal circumstances do support, a prevalence of vegetation typically

adapted for life in saturated soil conditions", and which are "navigable waters" as defined by

Section 502(7) of the Clean Water Act, 33 U.S.C. 1362(7).

Response 3894:

A definition of “wetlands” has been added to the revised regulations at 6 NYCRR 750-3, as “any

area regulated pursuant to Article 24 of the Environmental Conservation Law and any other

wetlands regulated under Section 404 of 33 U.S.C. 1251, et seq.”

Comment 3895:

The definition for Whole Effluent Toxicity, presently at 750-1.2(a)(99), should be renumbered as

750-1.2(a)(100).

Response 3895:

This comment is outside the scope of the regulatory changes proposed.

Comment 3896:

Part 750-1.7(a)(11) should be revised to specifically clarify that wetlands are included in the

definition of surface water bodies for the purposes of creating a topographic map. It should be

revised as follows: "A topographic map on a scale of approximately one inch equals 2000 feet

(or other map if a topographic map is unavailable) extending one mile beyond the property

boundaries of the source, depicting the facility and each of its intake and discharge structures;

each of its hazardous waste treatment storage and disposal facilities; the portion of the mapped

area on Indian Lands; and those all wells, springs, other surface water bodies (including

wetlands), and drinking water wells listed in public records, depicted on publicly-available

resource maps, or otherwise known to the applicant in the map area."

Response 3896:

This comment is outside the scope of the regulatory changes proposed. Where additional

requirements related to HVHF operations are necessary, the revised regulations at 6 NYCRR

750-3 include such. Additionally, the draft HVHF GP includes a number of mapping

requirements, such as distance to waterbodies. See also response to Comment 3894 regarding

the revised definition of wetlands.

Comment 3897:

An additional requirement for an individual State Pollutant Discharge Elimination System

(SPDES) permit application should be added to 750-1.7(a), requiring submittal of: "A map of on-

site and adjacent off-site surface water(s), wetlands and drainage patterns that could be affected

by the discharge."

Response 3897:


Comment 3898:

Part 750.3.2(6) defines BUD as a Beneficial Use Determination issued by the Department's

Division of Materials Management in accordance with 360-1.15. The Department's Division of

Water is responsible for ensuring that process water from shale gas extraction, including

production brine, are not permitted to run off into streams, creeks, lakes and other bodies of

water. As such, the Department's Division of Water would be the more appropriate entity to

evaluate whether or not wastewater associated with hydraulic fracturing can be used in road

spreading projects. However, the United States Environmental Protection Agency recommends

against the use of Beneficial Use Determinations for road-spreading projects and similar

applications.

Response 3898:

The revised regulations at 750-3 prohibit the discharge of flowback to the ground, but allow the

discharge of drilling fluids, formation fluids and production brine in accordance with the terms

and conditions of a BUD. The analysis for the BUD considers the geographic area and/or

specific roads on which the production brine can be spread and would take into account impacts

to water supply bodies or aquifers in the area. If approved, the BUD would restrict the quantity

of brine spread to minimize runoff of excess brine and potential impact to ground and surface

waters. Within the Department, the Division of Materials Management is responsible for the

issuance of BUDs.

Comment 3899:

Part 750-3.3 indicates the discharges that are prohibited and for which a State Pollutant

Discharge Elimination System permit cannot be issued. The federal effluent guidelines at 40

CFR 435.32 establish best practicable control technology currently available (BPT)

requirements: There shall be no discharge of waste water pollutants into navigable waters from

any source associated with production, field exploration, drilling, well completion or well

treatment (i.e., produced water, drilling muds, drill cuttings, and produced sand). The prohibition

of any discharge of wastewater pollutants into navigable waters from any source associated with

production, field exploration, drilling, well completion or well treatment (i.e., produced water,

drilling muds, drill cuttings, and produced sand) should be included in the prohibitions at 750-

3.3.

Response 3899:

The prohibited discharges in the draft regulations at 6 NYCRR 750-3.3 refer to siting of well

pads for HVHF operations. The revised regulations at 6 NYCRR 750-3 also include

requirements for high-volume hydraulic fracturing wastewater disposal, such as “Facilities

constructed specifically for the onsite treatment of HVHF wastewater are prohibited from

directly discharging to the waters of the State pursuant to 40 CFR Part 435. These onsite

facilities are not eligible to obtain a SPDES permit. All HVHF wastewater accepted and treated

by these onsite facilities must be either reused, as approved by the department, or transported for

offsite disposal at a permitted facility.” Additionally, the revised regulations at 6 NYCRR 750-3

and the draft HVHF GP do not authorize coverage under the HVHF GP for contaminated

stormwater discharges from drilling operations that are subject to BPT and BAT guidelines

found at 40 CFR 435.

Comment 3900:

Part 750.3-4(b)(3) states that applications for high-volume hydraulic fracturing must include a

certification that high-volume hydraulic fracturing flowback fluids will not be directed or stored

in a pit or impoundment. The proposed rule does not define pit or impoundment, but does define

"reserve pit."

Response 3900:

The Department recognized this concern and revised the regulations at 6 NYCRR 750-3 to state

“[f]lowback and production brine are prohibited from being directed to or stored in any reserve

pit or freshwater impoundment.”

Comment 3901:

The proposed rule does not include production brine whereas throughout the regulation,

flowback water and production brine are referenced together. Part 750.3-4(b)(3) should be

reworded as "Certification that high-volume hydraulic fracturing flowback fluids and production

brine will not be directed to or stored in a pit, impoundment or reserve pit."

Response 3901:


Comment 3902:

Part 750.3-11(i) requires that flowback water recovered after high-volume hydraulic fracturing

operations as well as production brine be tested for naturally-occurring radioactive materials

(NORM) which is defined under Part 750-3.2(32) as the radioactivity that can exist naturally in

native materials. Part 750.3-11(i) should specify the substances that testing must be completed

for. For instance, since water quality standards exist for radium 226, radium 228, gross alpha

radiation, and gross beta radiation, Part 750.3-11(i) must specify that at a minimum, radium 226,

radium 228, gross alpha radiation and gross beta radiation be tested using approved test methods

for wastewater (e.g., those found at 40 CFR Part 136).

Response 3902:

The requirement to test the ground adjacent to the tanks has been removed from the revised

regulations at 6 NYCRR 750-3, but is still a requirement of the revised regulations at 6 NYCRR

Part 560. See also Response to Comment 3904 regarding testing of HVHF wastewater,

including for NORM.

Comment 3903:

Part 750.3-11(i) should not distinguish between flowback water and production brine since, for

the purposes of federal direct discharge requirements, the two sources are regulated the same.

For wastewater testing, analytical methods and sampling protocols must conform to State

Pollutant Discharge Elimination System testing requirements. The section should be rewritten as:

Flowback water and production brine is prohibited from being directed to or stored in any pit,

pond or impoundment. Covered watertight steel tanks or covered watertight tanks constructed of

another material approved by the Department are required for flowback and production brine

handling and containment on the well pad. Flowback and production brine water tanks, piping

and conveyances, including valves, must be of sufficient pressure rating and be maintained in a

leak-free condition.

Response 3903:

See Response to Comment 3899 regarding federal direct discharge requirements. See Response

to Comment 3900 regarding reserve pits and impoundments. With respect to requirements for

the containment of flowback and production brine, the revised regulations at 6 NYCRR 750-3

cross-reference the revised regulations at 6 NYCRR Part 560.

Comment 3904:

Part 750-3.11 Application of Standards, Limitations and Other Requirements - Flowback water

and production brine recovered after high-volume hydraulic fracturing operations must be tested

for naturally-occurring radioactive materials (including, at a minimum, radium 226, radium 228,

gross alpha radiation and gross beta radiation) prior to removal from the site.

Response 3904:

The revised regulations at 6 NYCRR 750-3 include requirements for the various disposal options

for high-volume hydraulic fracturing wastewater. Each of these disposal options includes a

requirement to fully characterize the high-volume hydraulic fracturing wastewater and identify

the concentrations of chemical constituents present, as well as other parameters that may be

present in the high-volume hydraulic fracturing wastewater. This would include NORM.

NORM is defined in the revised regulations at 6 NYCRR 750-3.2.

Comment 3905:

Part 750-3.11 Application of Standards, Limitations and Other Requirements - The ground

adjacent to the flowback water and production brine tanks must be measured for radioactivity.

All testing must be in accordance with protocols satisfactory to the New York State Department

of Health and the Department.

Response 3905:


Comment 3906:

Part 750-3.11(k) states that flowback water and production brine shall not be discharged on the

ground surface. The provision should also include surface water. For instance, it should read,

"(k) Flowback water and production brine shall not be discharged on the ground surface or to

surface water."

Response 3906:

See Responses to Comments 3441 and 3900.

Comment 3907:

Part 750-3.12(d)(1)(vi) states the headworks analysis must demonstrate, among other things, that

the publicly owned treatment works (POTW) is capable of removing the contaminants expected

to be present in the flowback water and production brine, including but not limited to total

dissolved solids (TDS), naturally occurring radioactive materials (NORM), barium, bromides,

benzene, toluene, ethylbenzene, xylene and chemicals present in the additives used in the

development of the wells. Chlorides should be added to the list of parameters that must be

included since chlorides are usually present in high concentrations in hydraulic fracturing

wastewater and can interfere with biological wastewater treatment. The NORM parameters of

radium 226, radium 228, gross alpha radiation, and gross beta radiation should be specified

throughout the rule rather than the general term "NORM" so that the correct monitoring and

analysis is performed.

Response 3907:

See Responses to Comment 3781 regarding the headworks analysis and Comment 3904

regarding NORM.

Comment 3909:

Part 750-3.12(d)(1)(vi)(c)(3) indicates that each discharge of flowback water and production

brine to the headworks of the publicly-owned treatment works shall include an assay of the

concentrations of high-volume hydraulic fracturing chemicals present including total dissolved

solids, naturally-occurring radioactive materials (NORM), benzene, toluene, ethylbenzene, and

xylene. The provision should state that the concentrations must be performed using the approved

methods in 40 CFR Part 136 and specify that at a minimum NORM parameters of radium 226,

radium 228, gross alpha radiation, and gross beta radiation be included in the analysis.

Response 3909:

See Responses to Comment 3781 regarding the headworks analysis and Comment 3904

regarding NORM. 6 NYCRR 750-2.5(d) requires testing in compliance with 40 CFR Part 136.

As stated in the final regulations at 6 NYCRR 750-3.1, “Unless in conflict, superseded or

expressly stated otherwise in this Subpart, the provisions set forth in Subpart 750-1 and Subpart

750-2 of this Part shall apply to HVHF operations.”

Comment 3910:

Part 750-3.12(d)(4)(i) should be revised to replace "Type II" disposal wells with "Class II"

disposal wells.

Response 3910:

The revised regulations at 6 NYCRR 750-3 reference the Underground Injection Control

program, in general.

Comment 3911:

Part 750-3.12(d)(5)(iv) should be revised to replace "Sections 1423 and 1425" with "Section

1421".

Response 3911:

The references to Sections 1423 and 1425 are correct.

Comment 3912:

Part 750-3.12(d)(6) states that production brine may be disposed in accordance with the terms

and conditions of a Department-approved Beneficial Use Determination. Under 40 CFR 435.32,

wastewater from onshore oil and gas extraction, including production brine, cannot be

discharged into navigable waters. The Department should not issue Beneficial Use

Determinations for road spreading and similar applications.

Response 3912:


Comment 3913:

At 750-3.21(f)(4), the term "Wetland" in the table needs to be qualified as "ECL Article 24

mapped freshwater wetlands."

Response 3913:


Comment 4024:

Section 750-3.21(f)(4): This section is unclear. The word "buffer," is often used interchangeably

with the word "setback." Without being defined, it becomes confusing to call something a buffer

and then have a process to circumvent the "buffer" by applying for a high-volume hydraulic

fracturing individual permit. The section should eliminate the use of the word buffer. If the word

buffer is used, then both the words "buffer" and "setback" should appear in the Definitions at

750-3.2.

Response 4024:

The buffers described in the revised regulations at 6 NYCRR 750-3 are distances from water

resources. This term is used in revised regulations 6 NYCRR 750-3.11(d) with regard to where

HVHF operations are not authorized by the HVHF GP.

Comment 4025:

Section 750-3.21(f)(1) through (4): Construction of a centralized flowback impoundment is

presumably included as an "HVHF operation on the ground surface" and is thus prohibited under

750-3.3, Prohibited Activities and Discharges. The Department should confirm that centralized

flowback impoundments and their attendant piping are included in the definition of high-volume

hydraulic fracturing operations, thereby prohibiting them in the New York City and Skaneateles

Lake watersheds and elsewhere, specifically named in (1) through (4). If they are not included in

the high-volume hydraulic fracturing definition, they need to be added to the definition of

"Construction Phase," which is part of the high-volume hydraulic fracturing definition, or as part

of a separate definition of "Appurtenances."

Response 4025:

As set forth in the revised regulations at 6 NYCRR 750-3, construction and use of a centralized

flowback impoundment is not eligible for coverage under a stormwater general permit for HVHF

operations and so requires an individual SPDES permit and site-specific SEQRA review.

Comment 4026:

Section 750-3.12(d)(5)(v): "Long term" should be given a range of years.

Response 4026:

“Long-term” has been removed from the revised regulations at 6 NYCRR 750-3, but the

requirement remains that there be a monitoring program with periodic monitoring for chemical

constituents present, as well as other parameters that may be present in the high-volume

hydraulic fracturing wastewater.

Comment 4027:

Section 750-3.4(b)(5): Alternative plans should not be approved by the Department to decrease

the separation distance that has been stated multiple times - 1,000 feet below the base of fresh

groundwater, and at least 2,000 feet below the surface. Having a procedure for alternative plans

will put pressure on the Department to review and approve such plans. This could also be point

where political pressure could prevail over environmental protection. The job of the Department

permit application reviewers will be much easier if the separation distances are absolute.

Response 4027:

The revised regulations at 6 NYCRR 750-3 no longer use the term “alternative plans” for the

separation distance. However, the revised regulations do state that: “At a minimum, in order for

the department to make a determination that the injection will not result in the degradation of

ground or surface water resources pursuant to paragraph 750-3.5(b)(2) of this Part: (1) 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 ground surface and must be deeper than 1,000

feet below the base of a known freshwater supply.” Drilling at depths where the Department has

not made such a determination would require an individual SPDES permit and site-specific

SEQRA review.

Comment 4028:

Section 750-3.4(b)(4)(i): In addition to the certification for pyrite, certification for on-site pits

should contain ranges for naturally occurring radioactive materials (NORM) and heavy metal

content above which, the operator certifies that only closed loop system will be used. Other

heavy metals or metals, in addition to pyrite, could degrade surface drinking water quality, such

as arsenic, mercury, beryllium, and chromium-6. Currently the Environmental Protection Agency

re-evaluating the Maximum Contaminant Level in drinking water supplies for Chromium-6,

which can occur in rocks as Chromium-3 but can change to Chromium-6 in the erosion process

or when it comes in contact with chlorine in a drinking water supply system.

Response 4028: The revised regulations at 6 NYCRR 750-3 required that “A closed-loop tank system must be

used instead of a reserve pit to manage drilling fluids and cuttings, in cases set forth in paragraph

560.6(c)(7) of this Title, as adopted on XX, 20XX.” Revised 6 NYCRR 560.6(c)(7)(ii) requires

that a closed-loop system be used for “any drilling requiring cuttings to be disposed of off-site.”

Comment 4029:

Section 750-3.3(b)(1): New York City and Skaneateles Lake unfiltered water supply watersheds

should be specifically named.

Response 4029:

The revised regulations at 6 NYCRR 750-3 prohibit the siting of well pads for HVHF operations

in unfiltered drinking water supply watersheds, which is defined in revised 6 NYCRR 750-3 as

follows: “In New York State, this includes the New York City Drinking Water Supply

Watershed and the Syracuse Drinking Water Supply Watershed.”

Comment 4030:

Section 753-3.2, item 49, Definitions, Unfiltered water supplies means: The Department is urged

to add the following words in parenthesis to the definition to avoid confusion: "In New York

State, this includes the New York City Drinking Water Supply Watershed and the (City of

Syracuse's) Skaneateles (Lake) Drinking Water Supply Watershed."

Response 4030:


Comment 4032:

Section 750-3.2, item 35, Definitions, Partial site reclamation: The word scarified in the

construction industry indicates shallow cuts in the earth and is not appropriate for a site where

there was heavy industrial activity of the type that will occur on a well pad. Deep ripping will be

the best way to alleviate the deep compaction of a well pad. The word scarified should be

removed from the definition and wherever else it occurs in your documents. Also, it is not clear

in the definition if seeding and mulching is required to meet the definition of "partial site

reclamation." Perhaps this can be clarified by connecting the last sentence by use of a semicolon

to the prior sentence. "prior to replacement of topsoil; reclaimed areas have been seeded and

mulched after topsoil replacement and native vegetative cover reestablished that will ultimately

return the site to preconstruction conditions."

Response 4032:

The revised regulations at 6 NYCRR 750-3.2 define Partial Site Reclamation as “(a) when all of

the equipment, materials and BMPs associated with the HVHV Phase have been removed, (b)

surface disturbances not associated with production activities have been scarified or ripped to

alleviate compaction prior to replacement of topsoil, and (c) all the disturbed areas have been

stabilized after topsoil replacement, in accordance with the Partial Site Reclamation Plan

submitted pursuant to [6 NYCRR Part 560]. Partial reclamation and final reclamation of any

well pad and access road must be done in conformance with the plans approved by the

department.” The Department maintains guidance on deep ripping and decompaction, which

would be utilized to determine the degree of restoration of soil porosity necessary based on the

previous activity.

Comment 4033:

Section 750-3.2, item 16, Definitions, the following addition in parenthesis is suggested: "Final

stabilization means that all soil disturbance activities have ceased, (specified compaction

densities have been achieved [which may include compaction of disturbed subgrade and/or

placement or ripping of compacted layers of topsoil], final grading, and a uniform, perennial

vegetative cover ..."

Response 4033:

See Response to Comment 4032, regarding the requirements to deep rip and/or scarify in

accordance with Department guidance.

Comment 4034:

The Department should check that the definition of "Construction Phase" in Section 750-3.2

includes the construction of centralized flowback impoundments and their attendant piping. This

will ensure that such an impoundment could not be constructed in an unfiltered water supply or

other prohibited area.

Response 4034:


Comment 4571:

The term is used in 6 NYCRR 750-3.4(b)(3), requiring certification that high-volume hydraulic

fracturing flowback fluids will not be directed to or stored in a pit or impoundment. The

Department should specify if this is intended to include only the production brine that comes out

of the well immediately after completion or re-fracture, or if production brine surfacing long

after the initial completion or re-fracture is included as well. We can read the definition either

way and we suggest the Department clarify, because this ambiguity could lead to operator

uncertainty.

Response 4571:

See Responses to Comments 3900 and 3901. The revised regulations at 6 NYCRR 750-3

include definitions for flowback and production brine.

Comment 5687:

Section 750-3.3(b) bars installation of a well within 4,000 feet of "unfiltered surface water

supply watersheds." There is no definition of "surface water supply watersheds". Without a

definition, a well proponent could argue that the term only applies to a reservoir as juxtaposed to

streams and lakes that "feed" the reservoir. Please clarify the scope of the term.

Response 5687:

See Response to Comment 4029 regarding the definition of an unfiltered drinking water supply.

The revised regulations at 6 NYCRR 750-3 include the following prohibitions: “within 2,000

feet of any public (municipal or otherwise) drinking water supply well, reservoir, natural lake,

man-made impoundment, or spring; and within 2,000 feet around a public (municipal or

otherwise) drinking water supply intake in flowing water with an additional prohibition of 1,000

feet on each side of the main flowing waterbody and any upstream tributary to that waterbody for

a distance of one mile from the public drinking water supply intake.”

Comment 5688:

Section 750-3.21, (f)(4): The setbacks listed are inadequate. Suggested buffers: at least 1,500

feet from a private well and 4,000 feet from a lake.

Response 5688:


Comment 5691:

Section 750-3.12 (d) of the rdSGEIS states: "On-site facilities constructed specifically for the

treatment and reuse of [high-volume hydraulic fracturing] wastewater where the treated water is

100 percent reused for purposes of [high-volume hydraulic fracturing] do not require a [State

Pollutant Discharge Elimination System] permit." State Pollutant Discharge Elimination System

permits should be required for all wastewater treatment facilities. There should be no loopholes.

Response 5691:

When there is 100% reuse of high-volume hydraulic fracturing wastewater, there is no discharge

to a water of the State from a point source requiring a SPDES permit. The revised regulations at

6 NYCRR 750-3 include requirements for recycling of high-volume hydraulic fracturing

wastewater. The revised regulations at 6 NYCRR 554.1(c)(1) requires that the owner or operator

must state in its plan that it will maximize the reuse and/or recycling of used drilling mud,

flowback water and production brine, to the maximum extent feasible.

Comment 5708:

Section 750-3.4 of the rdSGEIS, Requirement to obtain a permit (b)(1): It is possible to remove

radium from flowback water and production brine at specialized facilities and licensed facilities

exist to accept radium filters and sludges.

Response 5708:

Comment noted. The revised regulations at 6 NYCRR 750-3 provide the requirements for

Department approval of the various options for disposal of HVHF wastewater.

Comment 5714:

Section 750-3.11 of the rdSGEIS, Applications of standards, limitations and other requirements

(h)(i): Flowback should be tested in an Environmental Laboratory Accreditation Program-

certified laboratory, specifically for radium, according to United States Environmental Protection

Agency protocols 903.0 or 903.1. Gamma testing for the surrogate Bi-214 should not be

permitted.

Response 5714:


Comment 5727:

Part 750-3.3, Prohibited Activities and Discharges (b) Prohibition of high-volume hydraulic

fracturing operations on the ground surface should be expanded to include the following areas:

(1) closer than [1,000 feet, 5,000 feet] from a private water well unless waived by the water well

owner; (2) within a the geometric boundary of a primary aquifer and a [2,000-foot, 4,000-foot,

5,000-foot] buffer from the boundary of a primary aquifer or surface water divide for the aquifer,

whichever is closer; (3) within a 100-year floodplain and a 500 foot buffer of the 100-year

floodplain; (4) within [500 feet, 1,000 feet] of a wetland; (5) within [2,000 feet, 5,000 feet] of

any public water supply (municipal or otherwise) well, reservoir, natural lake or man-made

impoundment (except engineered impoundments constructed for fresh water storage associated

with fracturing operations), and river or stream intake; (6) within 2,500 feet of any faults or

Fracture Intensification Domains that are mapped within 1,000 feet of any public water supply

(municipal or otherwise) well, reservoir, natural lake or man-made impoundment (except


operations), and river or stream intake; (7) within 1,000 feet of any active or abandoned salt

mine; (8) below a Finger Lake or dry Finger Lake valley and within 500 feet of the Finger Lake;

(9) within 500 feet of a perennial stream; (10) within 5,000 feet of a principal aquifer; (11)

within 5,000 feet of a sole source aquifer; (12) within 7 miles of an unfiltered water supply; and

(13) prohibited in MS-4 designated areas. No access roads to drill pads, or pipelines should be

permitted through wetlands, wetland buffers, agricultural lands, or state-owned lands.

Response 5727:


Comment 5728:

The term "uncontaminated" should be defined in the State Pollutant Discharge Elimination

System permit proposed regulations.

Response 5728:

6 NYCRR 750-1.2 does not contain a definition of “uncontaminated” and the Department does

not believe it is necessary to include a definition in the revised regulations at 6 NYCRR 750-3.

Also, the commenter does not propose a definition.

Comment 5751:

As a general observation, a number of these proposed regulations (Parts 52, 190, 550-560, 750)

are not clear and coherent as required by law. They do not provide the operators (or the

monitors) with a clear indication of what is allowed and what is prohibited. They need to be

more clearly defined in order to be properly interpreted and withstand the scrutiny and

challenges that will be presented by the lawyers and operators of drilling and energy companies.

Response 5751:

The revised regulations at 6 NYCRR 750-3 have been re-written for clarity and consistency.

Comment 5753:

An example of needless confusion in these proposed regulations is in Section 750-3.2

Definitions: (44) Reserve pit means a mud pit in which a supply of drilling fluid has been stored,

or a waste pit, usually an excavated pit. It may be lined to prevent soil contamination. This

suggests that a reserve pit as defined in this set of regulations does not require a pit liner when, in

fact, all subsequent regulations (e.g., see 560.6 (c) (7)) appear to require a liner. To avoid

confusion the definition should read, It must be lined with a (specified) liner to prevent soil

contamination. These revised regulations should be reviewed in detail and be written as simple,

clear directives for the benefit of both the operators and the monitor-regulators.

Response 5753:

A revised definition of “reserve pit” is included in the revised regulations at 6 NYCRR 750-3.2 -

“a lined, mud pit in which a supply of drilling fluid has been stored, or a waste pit, usually an

excavated pit.” The revised regulations at 6 NYCRR 750-3 do require that “[a]ny reserve pit,

drilling pit or mud pit on the well pad must be maintained in a leak free condition and

constructed, for any number of wells, in accordance with the requirements set forth in paragraph

560.6(a)(4) of this Title, as adopted on XX, 20XX. Additionally, such pits must be constructed,

coated, or lined with materials that are chemically compatible with the substance stored.”

Comment 5760:

750-3.12 Disposal of high-volume hydraulic fracturing flowback and production water,

Paragraph (6) of the proposed regulation for the disposal of flowback and production waters

presumes that flowback and production water can qualify for a Beneficial Use Determination and

be permitted for dust and ice control on roadways; however, this not consistent with rdSGEIS

Section 5.13.3.4 which notes that flowback fluids will not be eligible for Beneficial Use

Determinations which would be necessary for use for road spreading. Also, Section 7.1.7.2 of the

rdSGEIS prohibits production fluids from being spread on roads as well, and states, "the data

available to date associated with... naturally occurring radioactive materials... concentrations in

Marcellus Shale production brine is insufficient to allow road spreading under a Beneficial Use

Determination."

Response 5760:


Comment 5766:

The proposed 560.2(b)(12) definition of partial reclamation differs from the proposed 750-

3.2(35) definition. Moreover, the concept of partial site reclamation is unclear in both. This is a

very important issue because of the episodic nature of drilling and completion associated with

shale development. The proposed definition of partial site reclamation in 750-3.2(b)(35) should

be deleted.

Response 5766:

The regulations at 6 NYCRR 750-3 are for SPDES permitting, not gas well permitting. The

revised regulations at 6 NYCRR 750-3 define Partial Site Reclamation, whereas the regulations

at 6 NYCRR Part 560 define Partial Reclamation. Duplication and consistency have been

addressed, including cross-references in the revised 6 NYCRR 750-3 to the revised 6 NYCRR

Parts 550-556 and 560, where appropriate.

Comment 5767:

The proposed definition in 750-3.2(b)(16) for final stabilization should be deleted as

unnecessary. To the extent, however, that the Department elects to move forward with the

proposed definition, the reference to other equivalent stabilization measures should be defined or

examples should be provided to make it clear that other stabilization techniques are allowable

during non-growing seasons.

Response 5767:

The definition of “final stabilization” in the regulations at 6 NYCRR 750-3 has been revised as

follows: “all soil disturbance activities have ceased and a uniform, perennial vegetative cover

with a density of at least eighty (80) percent has been established or other equivalent stabilization

measures, such as sod, permanent landscape mulches, rock rip-rap or washed/crushed stone, have

been applied on all disturbed areas that are not covered by permanent structures, concrete or

pavement.”

Comment 5769:

The proposed regulations do not apply the formation fluids definition in 750-3.2(b)(19). It is

recommended that the proposed definition be deleted as unnecessary.

Response 5769:

The revised regulations at 6 NYCRR 750-3 do use the term “formation fluids,” and therefore, it

is unnecessary to delete.

Comment 5772:

Defining high-volume hydraulic fracturing Phase and high-volume hydraulic fracturing

Operations in the proposed 750-3.2(b)(23)-(24) to include drilling is confusing given the

common industry understanding distinguishing drilling and stimulation. It is also counter to the

proposed 560.2(b)(8) definition for high-volume hydraulic fracturing. It is recommended that the

defined term of high-volume hydraulic fracturing Phase be revised in both 750-3.2(b)(23) and

(24) to be the Drilling and high-volume hydraulic fracturing Phase, as well as throughout

proposed 750-3, and, further, that the definition of Drilling and high-volume hydraulic fracturing

Phase in subsection (b)(23) be amended as follows: any subsequent well drilling, stimulation and

re-stimulation event on the same well pad.

Response 5772:

The revised regulations at 6 NYCRR 750-3 define HVHF Phase to be “the phase following

Construction Phase Completion and through completion of Partial Site Reclamation. This phase

includes well drilling, high-volume hydraulic fracturing, and on-site handling and treatment of

HVHF wastewater produced until all wells planned for that well pad have been completed.” Re-

stimulation would trigger the requirements of the HVHF Phase in the draft HVHF GP. “HVHF

Operations” are different and broader, and include all the related phases (Construction Phase,

HVHF Phase, and Production Phase).

Comment 5774:

The proposed definition for a high-volume hydraulic fracturing general permit in 750-3.2(b)(25)

is unnecessary. There should be no permits issued; rather there should be qualification for a

multi-sector general permit written for the oil and gas industry. It is recommended that this

definition be deleted.

Response 5774:

The Multi-Sector General Permit for Stormwater Discharges from Industrial Activities does not

cover HVHF operations. HVHF operations do require coverage under the General Permit for

Stormwater Discharges from Construction Activities. The Department created the HVHF GP to

cover all phases of HVHF operations and streamline the permitting process.

Comment 5775:

The proposed definition at 750-3.2(b)(34) attempts to combine two terms (i.e., owner and

operator). This combined definition conflicts with the existing definitions of these terms set forth

in 560.3(ab) and (ad) and, therefore, should be deleted.

Response 5775:

The revised regulations at 6 NYCRR 750-3 utilize the definition of “owner or operator” from 6

NYCRR 750-1.2.

Comment 5777:

The proposed definition of plugged and abandoned in 750-3.2(b)(36) differs from the existing

definition in 550.3 (af) and, therefore, should be deleted.

Response 5777:

The regulations at 6 NYCRR 750-3 are for SPDES permitting, not gas well permitting.

Duplication and consistency have been addressed, including cross-references in the revised 6

NYCRR 750-3 to Division of Mineral Resources’ regulations, where appropriate.

Comment 5779:

The proposed definition of production phase in 750-3.2(b)(41) is inconsistent with custom and

usage in the industry, is confusing and does not take into account the gaps in time that will take

place prior to and in between the drilling of infill wells. Further, all wells planned needs to be

clarified to specify whether this requirement applies to a one-well pad and/or a multi-well-pad

permit. It is recommended that the defined term of production phase be revised to mean the

phase after the Drilling and high-volume hydraulic fracturing Phase.

Response 5779:

The revised regulations at 6 NYCRR 750-3 define “production phase” as “the phase following

Partial Site Reclamation through the termination of coverage under an HVHF general permit or

termination of an individual HVHF SPDES permit. This phase includes the production of

natural gas and the on-site handling and treatment of production brine at the well site.” See also

Response to Comment 5772.

Comment 5786:

The Department should delete 750-3.6 as the Department lacks jurisdiction to require an

individual State Pollutant Discharge Elimination System permit because there are no discharges

to the waters of New York State. Environmental Conservation Law Article 17 prohibits

discharges of pollutants into waters of the state without a permit (see Environmental

Conservation Law 17-0701, 17-0803, 17-0807[4]), or if such discharges will result in

contravening water quality standards (see Environmental Conservation Law 17-0501, 17-0301).

The Environmental Conservation Law defines waters of the state, and such include groundwater

as well as surface water. Environmental Conservation Law 17-0105(2) (waters of the state shall

be construed to include all other bodies of surface or underground water, natural or artificial

which are wholly or partially within or bordering the state or within its jurisdiction). Under the

plain language of the statute, hydraulic fracturing a well below any groundwater bearing zones

cannot be jurisdictional. Because high-volume hydraulic fracturing would occur in formations

well below the groundwater table, there is and can be no direct contact with any state waters and,

thus, there is no possibility of direct introduction of contaminants (i.e., discharge) to such waters.

In most areas of New York State, the groundwater table only extends several hundred feet below

the ground surface and rarely, if ever, is found below 1,000 feet below ground surface.

Response 5786:

ECL §17-0701 requires a SPDES permit for anyone to “[m]ake or cause to make or use any

outlet or point source for the discharge of sewage, industrial waste or other wastes or the effluent

therefrom, into waters of the state.” 6 NYCRR 750-2.1(a)(40) defines groundwater as “waters in

the saturated zone. The saturated zone is a subsurface zone in which all the interstices are filled

with water under pressure greater than that of the atmosphere. Although the zone may contain

gas-filled interstices or interstices filled with fluids other than water, it is still considered

saturated.”

Comment 5787:

If the Department is going to allow low volume oil and gas development in Filtration Avoidance

Determination (FAD) watersheds or other critical drinking watershed across the State it must

provide the proper environmental review and justification. In many situations vertical well

spacing presents greater surface impacts to drinking water than high-volume hydraulic

fracturing. The new regulations should set one standard for all oil and gas activity.

Response 5787:

The regulations at 6 NYCRR 750-3 apply to only high-volume hydraulic fracturing. See

Response to Comment 3855. High-volume hydraulic fracturing within the (unfiltered) New

York City and Syracuse drinking water supply watersheds may present a risk of causing

significant adverse impacts to these water supplies. As the only unfiltered surface supplies of

municipal water in the state, the New York City and Syracuse drinking water supply watersheds

are unique and deserve special protection to maintain their Filtration Avoidance Determinations.

Losing this designation would mean New York City and Syracuse would be required to spend

billions of dollars to build water filtration plants. The heightened sensitivity of these unfiltered

watersheds makes the potential for adverse impacts to water quality from sedimentation due to

the significant amount of construction activity that is projected to occur during levels of

projected peak activity unacceptable. The Department finds that standard stormwater control

and other mitigation measures would not fully mitigate the risk of potential significant adverse

impacts on water resources from this increased construction activity associated with high-volume

hydraulic fracturing. The revised regulations recognize that the increased industrial activity

associated with well pad development, road construction and other activities associated with

high-volume hydraulic fracturing is inconsistent with the long-term protection of unfiltered

surface drinking water supplies. Accordingly, the revised regulations include a prohibition of

high-volume hydraulic fracturing in both the New York City and Syracuse drinking water supply

watersheds, as well as in a 4,000-foot buffer area surrounding these watersheds.

Comment 5788:

Proposed Express Terms 6 NYCRR Part 750-3.4(b)(6) states, certification that high-volume

hydraulic fracturing operations will be conducted only where the top of the fracture zone at all

points along the proposed length of the wellbore is greater than both 2,000 feet below the surface

and 1,000 feet below the base of fresh groundwater. This is too stringent and will have the effect

of making many areas where shale resources are found off-limits to development. Moreover, this

requirement has no place in the water regulations, since the water regulations relate to surface

activities, not the hydraulic fracturing process itself. In addition to moving this requirement to

the minerals regulations, the Department should allow an applicant to demonstrate that there are

sufficient confining geologic layers to prevent contamination of the groundwater bearing zone

from the proposed hydraulic fracturing.

Response 5788:

The revised regulations at 6 NYCRR 750-3 require that “[t]he owner or operator must submit

documentation of the anticipated depth of the top of the objective formation, and the depth of the

base of the known freshwater supply, along the proposed length of the wellbore.” Additionally,

“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 ground surface and must be

deeper than 1,000 feet below the base of a known freshwater supply.” This information, along

with other information, is required in order for the department to make a determination that the

injection will not result in the degradation of ground or surface water resources.

Comment 5793:

If the Department does attempt to require an individual permit, 6 NYCRR Section 750-3.6(b)(3)

needs to be clarified. The Department assigns the American Petroleum Institute number, so the

number would not be known until the drilling permit is approved. This would further needlessly

restrict the industry because it would indicate that the owner/operator could not submit the

drilling permit and the high-volume hydraulic fracturing permit concurrently.

Response 5793:

The revised regulations at 6 NYCRR 750-3 removed the requirement that the API number be

submitted as part of a complete permit application. The same would be true for an NOI for

coverage under a stormwater general permit for HVHF operations.

Comment 5800:

The Department should provide scientific justification for its determination of setback distances.

For example: 750-3.3 (b) (1), 750-3.3 (b) (2), 750-3.3 (b) (4): Increase to two miles and include

subsurface activities, as well. Please explain the science behind the stated setback, and base the

answer on peer-reviewed papers published by non-industry or industry-affiliated or industry-

friendly sources.

Response 5800:


Comment 5806:

The proposed 6 NYCRR part 750 regulations are very confusing in that they seem to imply that a

State Pollutant Discharge Elimination System permit is required for high-volume hydraulic

fracturing, whereas the regulations specifically exempt that activity (750-1.1(g)). To

acknowledge the exemption, the high-volume hydraulic fracturing general permit should reflect

New York State’s current State Pollutant Discharge Elimination System Multi-Sector General

Permit for Stormwater Discharges Associated with Industrial Activities (GP-0-06-002) by

requiring the high-volume hydraulic fracturing general permit only for stormwater discharges

associated with industrial activity from oil and gas extraction which have had a discharge of a

reportable quantity of oil or a hazardous substance for which notification is required under

federal regulations. The Department also should modify the high-volume hydraulic fracturing

general permit to mirror Pennsylvania’s streamlined Erosion and Sediment Control General

Permit (ESCGP-1). The Pennsylvania permit requires robust planning for environmental

protection along with expedited permit review and authorization. New York should have a

similarly expeditious process, consistent with the process that is currently employed in the Multi-

Sector General Permit, to avoid time delays that will put New York State at a competitive

disadvantage with other shale producing states. Independent Oil and Gas Association estimates

that the cost to comply with the stormwater requirements of the proposed regulations will be

between $50,000 and $100,000 per well pad. This compares to costs ranging from $25,000 to

$40,000 per well pad in Pennsylvania for a comprehensive, but streamlined regulatory program.

Response 5806:

See Response to Comment 5774. See also the revised Regulatory Impact Statement regarding

cost.

Comment 5809:

There should be nothing that is in addition to what is set forth in the stormwater general permit

applicable to the oil and gas extraction industry. 750-3.4(a). The general permit should be self-

explanatory and self-implementing. (As further clarification, 750-3.4(b) should be clarified as

individual high-volume hydraulic fracturing State Pollutant Discharge Elimination System

permit, since the definition of that permit includes both an individual and a general permit).

Response 5809:

The revised regulations at 6 NYCRR 750-3 state “Unless in conflict, superseded or expressly

stated otherwise in this Subpart, the provisions set forth in Subpart 750-1 and Subpart 750-2 of

this Part shall apply to HVHF operations.” There are portions of the regulations at 750-1 and

750-2 that apply to HVHF operations.

Comment 5810:

It is unreasonable to require certification of disposal capacity for the life of the well, since shale

wells may last for many decades (6 NYCRR Sections 750-3.4 (b)(1), 750-3.12). Instead, the time

limit on capacity certification should be no greater than five years of disposal.

Response 5810:

The revised regulations at 6 NYCRR 750-3 no longer require certification of disposal capacity

for the life of the well. The revised regulations at 6 NYCRR 750-3 require a Fluid Disposal

Plan, identifying the ultimate disposition of HVHF wastewater, as well as a requirement that

upon renewal of a SPDES permit, the well owner provide documentation of compliance with the

requirements for a Fluid Disposal Plan. Similar regulatory requirements apply to coverage under

a stormwater general permit for HVHF operations and renewal of that coverage. See Response

to Comment 3441.

Comment 5814:

A separate State Pollutant Discharge Elimination System permit for drilling and completion

(750-1.1(g)) is duplicative of the minerals regulations. For the reasons detailed in Independent

Oil and Gas Associations Critical Issues Analysis, the Department should not require a State

Pollutant Discharge Elimination System permit. Therefore, 750-1.1(b), 750-1.5(a)(6) and 750-

3.4 should be deleted. If any separate review is required beyond the review of the qualification

for the Multi-Sector General Permit, it should happen contemporaneously with the well permit

application, not sequentially.

Response 5814:

See Response to Comment 5774. The regulations at 6 NYCRR 750-3 are for SPDES permitting,

not gas well permitting.

Comment 5816:

Any application requirements should be contained in the minerals regulations and the singular

application requirements should serve as a checklist for a complete application and compliance

with the GEIS and the SGEIS. For example, the following water regulations are already covered

in the mineral regulations and should be deleted: - 750-3.11(e)(1)(i) - 750-3.11(e)(1)(ii) - 750-

3.11(e)(1)(iii) - 750-3.11(e)(1)(v) - 750-3.11(e)(1)(vi) - 750-3.11(e)(1)(vii) - 750-3.11(f) - 750-

3.11(h) - 750-3.11(i) - 750-3.11(j) - 750-3.13.

Response 5816:

The regulations at 6 NYCRR 750-3 are for SPDES permitting, not gas well permitting.


NYCRR 750-3 to the revised 6 NYCRR Parts 550-556 and 560, where appropriate.

Comment 5817:

Part 750-3.4 must not allow open pits for storage of drilling materials.

Response 5817:

Revised regulations at 6 NYCRR 750-3 are consistent with the revised regulations at 6 NYCRR

Parts 550-556 and 560, regarding open pits for storage of drilling materials, which includes

construction requirements (e.g., liners, time limitation for storage). See Response to Comment

3900.

Comment 5818:

The Department needs to clarify 750-3.4(b)(4)(ii) regarding the volume of on-site pits to specify

what creates related tracts. The Independent Oil and Gas Association recommends that this be

changed to well pad.

Response 5818:


Comment 5822:

Section 750-3.4(b)(4)(viii) should be deleted as an unnecessary requirement. Alternatively, 750-

3.4(b)(4)(viii) should be clarified to explain what chemically compatible with the environment

means.

Response 5822:


Comment 5826:

Section 750-3.4(b)(6), which requires a certification that high-volume hydraulic fracturing

operations will be conducted only where the top of the fracture zone at all points along the

proposed length of the wellbore is greater than both 2,000 feet below the surface and 1,000 feet

below the base of fresh groundwater, needs clarification because geologic names for many

sequences may carry through larger areas where the action fracture zone may be a subset of this

formation; i.e., is the Point Pleasant a separate section of the Utica Shale?

Response 5826:


Comment 5828:

If the Department elects not to delete 750-3.13(f), alternatively, 750-3.1(f) must be clarified

because a continuous recording device for all production and flowback is technically difficult

and does not seem to be a necessary requirement, given the provision to record the volume of all

flowback and production brine (see 750-3.13(g)).

Response 5828:

The Department believes that it is necessary to have accurate information regarding the volume

of production and flowback. The revised regulations at 6 NYCRR 750-3 now read “with an

automatic continuous recording device or equivalent…” to allow for more flexibility in meeting

this requirement.

Comment 5830:

Section 750-3.4(b)(8) requirement for a certification that the applicant will utilize chemical

additive products that are efficacious exhibit reduced aquatic toxicity, and pose less risk to water

resources and the environment or, as an alternative, documentation to the Departments

satisfaction that the available alternative products are not equally effective or feasible restricts

competitive operations between service companies and may force the elimination of a

competitive environment for services. The regulations should not dictate a specific product based

on a generic goal.

Response 5830:

The regulations do not dictate a specific product based on the goal stated. See Response to

Comment 3438.

Comment 5831:

750-3.3 Prohibited Activities and Discharges should be modified to read (a) The prohibitions in

this section are in addition to those listed in section 750-1.3. The following high-volume

hydraulic fracturing (HVHF) activities and discharges are hereby prohibited, and no State

Pollution Discharge Elimination System (SPDES) permit shall be issued authorizing any such

activity or discharge. All distances noted below are measured from the closest edge of the HVHF

well pad to provide a margin of safety. (b) HVHF operations on the ground surface are

prohibited in the following areas: (1) Within 500 feet of, and including, a primary aquifer; (2)

Within 100-year floodplains; and (3) within 2,000 feet of any public (municipal or otherwise)

water supply, including wells, reservoirs, natural lakes or man-made impoundments, and river or

stream intakes; and not within 4,000 feet of the intake in an unfiltered public surface water

supply watersheds;

Response 5831:


Comment 5832:

Section 750-3.5(b) unjustly allows the Department to change any previously-issued

determination in the event that the permittee fails to implement any measure described in the

certifications submitted in compliance with 750-3.5. Under this scenario, an operator could

invest millions of dollars in a well only to have their general permit revoked, which would mean

that the operator could be subject to an extended permit process to obtain an individual State

Pollutant Discharge Elimination System permit. Independent Oil and Gas Association, therefore,

recommends that this provision be deleted.

Response 5832:

The revised regulations at 6 NYCRR 750-3 state “The department may change any previously-

issued determination in the event that the permittee fails to comply with any requirement

described in this subdivision or such injection results in the degradation of ground or surface

water resources.” The Department must ensure that the well owner complies with all of the

requirements; if not, then the Department must maintain its authority to address non-compliance,

which may include revocation of such determination.

Comment 5835:

Section 750-3.6(c), which prohibits an owner or operator from commencing the Construction

Phase until its authorization to discharge under the high-volume hydraulic fracturing State

Pollutant Discharge Elimination System permit is effective should be deleted. This clause

indicates that an owner/operator cannot construct a well pad until the Department approves the

discharge plan. There should be one stop shopping for a single permit from the Department. The

Division of Minerals should approve all of these activities in order to avoid timing issues.

Response 5835:

The regulations at 6 NYCRR 750-3 are for SPDES permitting, not gas well permitting. In

general, all construction activities in New York State subject to the thresholds in the SPDES

General Permit for Stormwater Discharges from Construction Activities must be covered under

that General Permit prior to any land disturbance. This same concept holds true for HVHF

operations, as the revised regulations at 6 NYCRR 750-3 mandate that “HVHF operations cannot

commence without a valid HVHF SPDES permit,” and this includes the Construction Phase.

The revised regulations at 6 NYCRR 750-3 require that for an individual SPDES permit, the

owner or operator must develop and submit a final Comprehensive SWPPP to the department.

Similar requirements apply for coverage under a stormwater general permit for HVHF

operations.

Comment 5836:

The proposed requirements of 750-3.11(d) that are contemplated prior to submission of the final

Notice of Termination appear to be without authority or precedent. Independent Oil and Gas

Association, therefore, recommends that the entire subsection be deleted.

Response 5836:

This requirement is consistent with the requirements of the General Permit for Stormwater

Discharges from Construction Activities, which applies to all construction activities in New

York State subject to the thresholds in the Construction General Permit prior to any land

disturbance. The requirements of the Construction General Permit apply to well pads

constructed in accordance with the 1992 SGEIS.

Comment 5839:

Section 750-3.11(e)(1)(iv): The owner or operator shall, prior to commencing the high-volume

hydraulic fracturing Phase ... (b) ensure that all areas of disturbance have achieved final

stabilization should be clarified because an operator cannot still be developing the site and

achieve final stabilization. Instead, Independent Oil and Gas Association recommends the

language have been stabilized. Further, Independent Oil and Gas Association recommends that

language be inserted into subparagraph (c) to account for ongoing stabilization that may be

occurring at the site.

Response 5839:

The revised regulations at 6 NYCRR 750-3 do incorporate this concept through the definition of

Construction Phase Completion, which means “ when (a) all construction activities in the

Construction SWPPP have been completed; (b) all the areas of disturbance have achieved final

grade and measures have been applied that will achieve final stabilization; and (c) all post-

construction stormwater management practices have been constructed in conformance with the

Construction SWPPP and are operational.” The HVHF Phase may commence after this point.

The revised regulations at 6 NYCRR 750-3 require that final stabilization must be achieved

within four weeks of the implementation of final stabilization measures unless otherwise

approved by the department.

Comment 5840:

Section 750-3.11(e)(1)(iv)(c): ensure that all temporary, structural erosion and sediment control

measures have been removed indicates that there will be no temporary structures during the high-

volume hydraulic fracturing phase. There is a need for temporary erosion design near fracturing

tanks and water storage that may be removed post stimulation, making 750-3.11(e)(1)(iv)(c)

impractical unless further defined.

Response 5840:

See Response to Comment 5839. Temporary erosion design near tanks and water storage is not

associated with the Construction Phase and should be implemented as necessary.

Comment 5841:

The proposed regulations fail to identify what happens when headworks analyses of the

flowback or production brine include unlisted contaminants, such as heavy metals. The

regulations should require that drilling activity is immediately suspended when flowback or

production brine are discovered to include materials not included in the headworks analysis.

Drilling activity should not resume before appropriate disposal mechanisms are identified.

Response 5841:

See Responses to Comments 3441 regarding the Fluid Disposal Plan and 3781 regarding the

headworks analysis. A drilling permit will not be issued until the well owner has an approved

Fluid Disposal Plan. The revised regulations at 6 NYCRR 750-3 require that the headworks

analysis must meet the requirements of 40 CFR Part 403, including a representative assay of the

concentrations of chemical constituents present, as well as other parameters that may be present

in the HVHF wastewater. As per the revised regulations at 6 NYCRR 750-3, notification must

be provided to DEC and EPA of any new introduction of pollutants or substantial change in the

volume or characteristics of the HVHF wastewater. 6 NYCRR 750-2.9(a)(2) states “[u]nless the

department determines that such permit modification is unnecessary, the noticed Act is

prohibited until the permit has been modified pursuant to [6 NYCRR Part 621].”

Comment 5845:

The Department should delete 750-3.21, given the detailed requirements set forth in the proposed

general stormwater permit. That being said, any necessary regulations that are not transferred to

the minerals regulations should be contained in 750-3.21 alone. In addition, the language should

make clear that the regulations govern compliance with the general permit and do not create any

new permitting requirements that might be interpreted as being subject to the Uniform

Procedures Act and give rise to the right to an adjudicatory hearing. If the Department chooses

not to delete 750-3.21, Independent Oil and Gas Association offers the following specific

recommendations: - Section 750-3.21(f)(3) high-volume hydraulic fracturing operations where

the top of the target fracture zone at any point along the entire proposed length of the wellbore is

shallower than 2,000 feet below surface; and where the top of the target fracture zone at any

point along the entire proposed length of the wellbore is less than 1,000 feet below the base of a

known fresh water supply needs to be made consistent with the recommendations that would

allow waivers of these depth and separation requirements based upon a demonstration that

confining geologic layers exist that will protect the freshwater bearing zone. - Section 750-

3.21(f)(5) cites to Best Available Technology Economically Achievable or Best Practicable

Control Technology Currently Available guidelines found at 40 CFR Part 435 which applies in

subpart C to onshore drilling. The Department needs to evaluate the scope of this disqualification

and put it into the context that contaminated stormwater discharges from oil and gas production

sites are not intended. - Because only stormwater will be discharged from high-volume hydraulic

fracturing operations and the Department has proposed multiple, independent, redundant

safeguards to preclude contamination from leaving the site, 750-3.21(f)(9)-(10) should be

deleted. - The proposed 750-3.21(k) would allow the Department to require any discharger

authorized to discharge in accordance with the high-volume hydraulic fracturing general permit

to apply for and obtain an individual State Pollutant Discharge Elimination System permit.

Section 750-3.21(k) also would allow the Department to terminate coverage under the general

permit without any basis. As such, an operator could be in the middle of a multimillion dollar

investment only to have its general permit coverage revoked, which would require it to obtain an

individual State Pollutant Discharge Elimination System permit that could take an extended

period of time and be subject to adjudicatory hearings. This type of unfettered discretion should

be eliminated from the regulatory proposal. The Department has indicated that this is not

intended to provide the agency with the right to require an individual State Pollutant Discharge

Elimination System permit after an operator has qualified for a general stormwater permit.

Independent Oil and Gas Association, therefore, suggests that the Department add clarifying

language that is both necessary and appropriate. - Section 750-3.21(o) states that unless and until

a fee is promulgated specifically for the high-volume hydraulic fracturing general permit, high-

volume hydraulic fracturing operations are considered a State Pollutant Discharge Elimination

System permit for stormwater discharges from construction activity for purposes of assessing

State Pollutant Discharge Elimination System general permit fees. The Department lacks any

legal basis for this provision. Independent Oil and Gas Association, therefore, recommends that

it be deleted.

Response 5845:


NYCRR 750-3 to the revised 6 NYCRR Parts 550-556 and 560, where appropriate. See

Responses to Comment 5788, Comment 3899, and Comment 5774. Existing regulations at 6

NYCRR 750-1.21(e) allows the Department to require an individual SPDES permit or a general

permit (included in revised 6 NYCRR 750-3.11(l)(1)). Revised regulations at 6 NYCRR 750-

3.11(l)(3) allows the Department to stop work at a well site under certain circumstances. Article

72 of the ECL establishes the fees for SPDES general permits, and as the HVHF GP contains

requirements for construction, the applicable fees are those that are in Article 72 for construction

activities.

Comment 5846:

Section 750-3.25(d) regarding monitoring of stormwater discharges during the Construction,

high-volume hydraulic fracturing and Production Phases needs to be clarified to specify what

needs to be monitored and recorded and what needs to be effectively operated. Continuous

recording of stormwater discharges is unreasonable and not possible. Also, the reporting

requirement would need to specify a timeline. For typical State Pollutant Discharge Elimination

System permits, reporting is monthly with permit conditions monitored as required by permits,

such as continuous or grab or intermittent. Finally, the Department needs to clarify how this can

apply to temporary facilities.

Response 5846:

The specific requirements for monitoring (e.g., parameters, frequency) are not appropriate for

inclusion in a regulation and would be contained within an individual SPDES permit or are

contained in a stormwater permit for HVHF operations. See Response to Comment 5828. The

regulations at 6 NYCRR 750-3 state that “[a]ll stormwater discharges must be monitored,

recorded and reported in accordance with the terms and conditions of an applicable HVHF

SPDES permit to ensure effective operation of the stormwater controls.” The draft HVHF GP

does not require stormwater monitoring during the Construction Phase.

Comment 5847:

The baseline testing contemplated by the stormwater program goes beyond what is required for

any other stormwater permit in New York State and exceeds the monitoring requirements for

most prominent facilities to manage hazardous substances and hazardous wastes. Independent

Oil and Gas Association estimates the cost to conduct all of the benchmark monitoring

contemplated by the stormwater regulatory program to be $50,000 per well pad. This compares

to $5,000 per well pad for compliance with the benchmark testing required under the existing

multisector general permit. As noted in other sections of comments, any contamination coming

from a well pad is likely to contain chlorides, which is why chlorides is the most common

benchmark testing parameter for discharges from a well site. The benchmark testing

contemplated by the proposed stormwater program is designed to require each operator to prove

the negative; i.e. that no contaminants have been discharged from the site, but that same

objective can be met with the existing benchmark testing requirements. Since a number of small

businesses are implicated in this requirement, the Department is legally obligated to look for

more cost-effective alternatives, the most logical of which is to continue the existing benchmark

testing requirements.

Response 5847:

The Department’s objective is to verify compliance with all regulatory and permit requirements

and ensure that all the engineering design and BMPs have been effective with an environmental

monitoring and sampling program. This concept is consistent with other SPDES permits for

stormwater discharges from industrial activities. The frequency of the monitoring is reflective of

the amount of activity being conducted on the well site, and as such will be reduced during the

Production Phase. The reporting parameters for the benchmark monitoring parameters are

associated with various activities that are being conducted on the well site. The Department

believes the costs identified in the comment are significantly overestimated. For example the

Department estimated the cost utilizing best available information at less than $1,000 per

stormwater sample.

Comment 5848:

Sections 750-3.12(b)(4),(6) regarding the required elements of the proposed Disposal Plan do not

provide for confidential business information, which is inconsistent with the way the issue is

treated elsewhere in the proposed regulations (see 750-3.13(e)). To resolve this omission, the

following should be added to the proposed section 750-3.12: This Disposal Plan may exclude

any information that has been identified as confidential business information. A similar concern

exists relative to Section 750-3.12(d)(1)(vi)(c) regarding the documentation required for a

discharge of flowback water and production brine to the headworks of a Publicly Owned

Treatment Works. Thus, the following should be added to section 750-3.12(d)(1)(vi): This

documentation may exclude any information that has been identified as confidential business

information.

Response 5848:

The information required to be provided to the Department for the headworks analysis or

treatability analysis would be available to the public, subject to the limitations of the Freedom of

Information Law. See Response to Comment 3441.

Comment 5850:

The Department should not specify disposal options and should encourage recycling and

beneficial reuse (750-3.12(d)). Further, 750-3.12(d) should be deleted because it applies to

wastewater treatment plant operations rather than oil and gas operations. Alternatively, if the

Department does not delete this requirement, 750-3.12(d)(1)(vi), regarding the required

demonstration, should be limited to Publicly Owned Treatment Works permitted limits.

Response 5850:

The revised regulations at 6 NYCRR 750-3 do not choose a disposal option and do not

encourage one suitable disposal option over another. The revised regulations at 6 NYCRR 750-3

provide the requirements for each of the options to be approved by the Department and where

appropriate requirements on the well owner or operator for disposal of HVHF wastewater. See

Response to Comment 3441.

Comment 5854:

Section 750-3.12(d)(1)(vi) requirement that the headworks analysis must demonstrate, among

other things, that the Publicly Owned Treatment Works is capable of removing the contaminants

expected to be present in the flowback water and production brine, including but not limited to

Total Dissolved Solids, naturally occurring radioactive materials, barium, bromides, benzene,

toluene, ethylbenzene, xylenes, and chemicals present in the additives used in the development

of the wells is too open ended and too restrictive. Publicly Owned Treatment Works are required

to treat influent to meet discharge limitations and not to remove all of the contaminants in the

influent. Independent Oil and Gas Association, therefore, recommends that the Department

revisit this requirement to narrow the requisite demonstration and the requisite level of treatment.

Response 5854:

The Department recognized this concern and the revised regulations at 6 NYCRR 750-3 require

that the headworks analysis must demonstrate that the HVHF wastewater will not cause a

violation of the POTW's effluent limits or sludge disposal criteria, and will not result in pass

through of substances present in the HVHF wastewater, or adversely affect the POTW's

treatment process. See also Response to Comment 3481 regarding the headworks analysis,

generally.

Comment 5855:

Section 750-3.12(d)(1)(vi)(c) regarding each discharge of flowback water should be plural.

Otherwise, it would limit flowback to individual wells with no comingling on a multiple well

pad. In addition, 750-3.12 (d)(1)(vi)(c)(3) suggests that the regulations will require a listing of

the concentrations of each chemical in the flowback relating to the same list of chemicals

supplied as used in high-volume hydraulic fracturing treatment. This is unnecessary given the

chemical analysis proposed in this section.

Response 5855:

The revised regulations at 6 NYCRR 750-3 provide the requirements for each of the disposal,

treatment or recycling options to be approved by the Department and where appropriate

requirements on the well owner or operator for disposal of HVHF wastewater. See Response to

Comment 3441.

Comment 5857:

Section 750-3.12(d)(3)(ii) which prohibits any remaining residuals at the site following

completion of well development is unclear. Independent Oil and Gas Association reccommends

that the section be clarified to indicate whether this is the completion phase or the production

phase.

Response 5857:

The revised regulations at 6 NYCRR 750-3 state “[p]rior to acceptance of any HVHF

wastewater, the onsite facility must demonstrate to the department that it has an approved

method of disposal of residuals in compliance with Parts 360, 364, 380, and 381 of this Title and

subdivision 750-2.8(e) of this Part.” This requirement is independent of the phase of HVHF

operations.

Comment 5859:

Section 750-3.12(d)(5) regarding the injection of production brine into the strata from which it

was produced pursuant to a State Pollutant Discharge Elimination System permit is unnecessary

and should not be applied to well stimulation. Independent Oil and Gas Association, therefore,

recommends that it be deleted.

Response 5859:

The requirements for deep well injection in the revised regulations at 6 NYCRR 750-3 do not

apply to well stimulation, but are rather for the disposal of HVHF wastewater.

Comment 5860:

Section 750-3.12(d)(5)(v), which purports to require a long-term monitoring program should be

deleted, as a monitoring well is not required under the regular underground program, as outlined

in 750-3.12(d)(5). Alternatively, long-term monitoring should only be required where there has

been a spill that requires reporting and the nature and extent of the monitoring should be based

upon the site specific circumstances.

Response 5860:

For deep well injection, the revised regulations at 6 NYCRR 750-3 require “(iii) installation of

upgradient and downgradient monitoring wells and a monitoring program with periodic

monitoring for chemical constituents present, as well as other parameters that may be present in

the HVHF wastewater.” The department has determined that this is an appropriate requirement

to ensure the protection of groundwater resources from deep well injection.

Comment 5861:

The proposed regulations should clarify that issuance of a State Pollution Discharge Elimination

System permit does not preclude the need to comply with local stormwater management laws

adopted in accordance with the Department's Municipal Separate Storm Sewer Systems

requirements.

Response 5861:

It is not appropriate for the Department’s regulations for HVHF operations to clarify the

application of local laws. The Department’s MS4 General Permit may contain separate

requirements. The preemption of local regulation is governed pursuant to ECL §23-0303(2),

which provides that the Department’s Oil, Gas and Solution Mining Law supersedes all local

laws relating to the regulation of oil and gas development except for local government

jurisdiction over local roads or the right to collect real property taxes. The scope of that

preemption will be determined by the courts. However, ECL §23-0305(13) requires every

person granted a permit to drill to notify any affected local government and surface owner prior

to commencing operations.

Comment 5865:

Marcellus Shale cuttings containing pyrite would be allowed to be buried on site if an approved

alternate disposal plan were submitted. No mention is made in the proposed regulations as to

what constitutes an alternate plan, and no examples are provided. Potential acid rock leaching

could result if an appropriate disposal and containment plan is not properly implemented.

Consequently, United States Fish and Wildlife recommends that the proposed regulations be

revised to include this information.

Response 5865:

The revised regulations at 6 NYCRR 750-3 require “[a] closed-loop tank system must be used

instead of a reserve pit to manage drilling fluids and cuttings, in cases set forth in paragraph

560.6(c)(7) of this Title, as adopted on XX, 20XX.” Acid rock drainage (ARD) mitigation plans

may be designed to neutralize acid drainage through the emplacement of basic carbonate

materials (e.g., waste lime or limestone cuttings) prior to on-site burial. The pyritic drill cuttings

and the carbonate materials would be mixed thoroughly and compacted prior to reclamation of

the pit area. This method was demonstrated to be effective in an ARD-abatement project jointly

conducted by Penn DOT and PADEP during construction of U.S. Route 22 near Lewiston, PA in

2004.

Comment 5867:

It is proposed that waste fluids be removed from the drilling site within 45 days of well

completion. United States Fish and Wildlife questions why this time period is so long. Some

states (ex/ Virginia) require removal of waste fluids immediately upon well completion. This

would reduce the likelihood of spills or accidents on the well site and adjacent areas, and the

corresponding risk of release on nearby resources. United States Fish and Wildlife recommends

that the proposed regulations be revised to require removal of waste fluids immediately if

possible, or within seven days at a maximum, in order to minimize the likelihood of accidental

exposure.

Response 5867:

The revised regulations at 6 NYCRR 750-3 require “The owner or operator must remove all

drilling fluid, formation fluid, or flowback from the well site consistent with paragraph

560.6(b)(2) of this Title, as adopted on XX, 20XX, and subdivision 560.7(a) of this Title, as

adopted on XX, 20XX.” The 45-day requirement is in existing regulations from Division of

Mineral Resources.

Comment 5870:

A Stormwater Pollution Discharge Elimination System permit is proposed to be required for

high-volume hydraulic fracturing as outlined in Section 750 of 6 NYCRR. Areas to be excluded

from drilling are listed in Section 750-3.3. The current proposed regulations require a 150 foot

well setback from aquatic areas, but the setback may be reduced if a site specific review is

undertaken. United States Fish and Wildlife believes that sensitive areas, such as aquatic

vegetation communities, should be provided adequate buffers so that construction activities,

spills, etc., do not impact water quality and habitat. The Delaware River Basin Commission

(DRBC) has proposed a minimum buffer of 300 feet from wetlands in that watershed (DRBC

2011). To be consistent with the Delaware River Basin Commission and more protective, it is

recommended that the Department adopt the distance of a 300 foot setback from aquatic habitat

(streams, lakes, etc.).

Response 5870:

See Response to Comment 2453. The revised regulations at 6 NYCRR 750-3 require an

individual SPDES permit, and site-specific SEQRA reviews, for HVHF operations within 300

feet of wetlands and “perennial or intermittent streams, as described in Parts 800-941 of this

Title, storm drains, lakes, or ponds.”

Comment 5872:

Support for the Department's proposal requiring the preparation of a hydraulic-fracturing specific

general stormwater permit for gas drilling operations addressing potential impacts to stormwater

on a case-by-case basis. Assuming realistic criteria and thresholds are established within the

general permit, implementation of this process could significantly streamline the permitting

process from both the applicants and the permitting agency’s perspective.

Response 5872:

Comment noted.

Comment 5873:

Requirements for Stormwater Pollution Discharge Elimination System permits are found in

Section 750-3.11 (e)1(i) and include a review of less toxic chemical alternatives to existing

hydraulic fracturing fluids used in most wells. A driller is required to investigate the toxicity,

mobility, and volume of available alternatives. United States Fish and Wildlife supports the

Departments position to seek less toxic chemical alternatives; however, the regulations should

state that the use of less toxic alternatives be used. Further, the proposed regulations are not clear

on what specific information is being sought. It is not clear if the Department is looking for

toxicity data related to a certain type of organism or representatives of many. For example, data

may be available for toxicity of a specified chemical to aquatic invertebrates but not plants,

herpetofauna, fish, mammals, or birds. Please revise the regulations to be more specific.

Alternatively, the Department could produce a separate document which specifies the parameters

needed for alternative chemical review. Furthermore, in the event that the requested data are

unavailable, the proposed regulations are unclear as to what would occur in that situation. It

should be clearly stated that additional studies, such as bioassays, may be warranted for alternate

additives, if insufficient information currently exists. United States Fish and Wildlife offers

assistance to the Department to work on this issue with industry.

Response 5873:


Comment 5874:

Section 750-3.12 discusses disposal of hydraulic fracturing flowback fluid and production water.

Flowback fluid and production brine are required to be disposed of properly over the life of the

well. The driller is expected to certify that a treatment and disposal facility will be able to handle

the projected amount of fluids; however, it is unclear how the ongoing capacity of such facilities

will be documented at any given time. United States Fish and Wildlife recommends that

flowback fluids be traceable (for example, dyes could be required) in the event that spills,

migration, or release occurs in the environment. The addition of a dye would allow regulators to

confirm the origin of the fluid and make a comparison to naturally occurring chemical

compounds, such as methane. United States Fish and Wildlife recommends the Department

require the use of dyes in drilling fluids so that flowback water and production brine may be

traceable.

Response 5874:

See Response to Comment 3441 regarding the Fluid Disposal Plan. The Department anticipates

utilizing a waste tracking form, which will be completed and maintained by generators, haulers

and receivers of all flowback water associated with HVHF operations. See regulations at 6

NYCRR 560.5(f) and (g).

Comment 5878:

The Department proposes to allow production brine to be disposed of in injection wells, in

accordance with a Beneficial Use Determination or by other means proposed by the permittee. A

Beneficial Use Determination is not described in Section 750-3.12 (6) nor are examples

provided. However, a common use in Pennsylvania is to spread the production brine on roads in

winter to melt ice and snow (Pennsylvania Department of Environmental Protection 2011b).

United States Fish and Wildlife are concerned that this use has not been properly studied to

determine the short or long term effects of production brine on fish and wildlife or their habitats.

To our knowledge, no adequate studies have been conducted on the toxicity of production brine

in New York. Further, no studies have been conducted on the cumulative effects of brine on

water quality. United States Fish and Wildlife recommends that a Beneficial Use Determination

not be issued for any production brine until an adequate study has been completed on the effects

to fish and wildlife.

Response 5878: See Response to Comment 3898 regarding BUDs. For clarification, beneficial use

determinations granted under 6 NYCRR 360-1.15 are not for disposal but for the acceptable

reuse of a solid waste.

Comment 5880:

Currently, the draft regulations allow for the driller to maintain a record on water use, chemical

use, and the volume of flowback fluids and production brine delivered from the well. Although

records of the fluids and chemicals used and produced on each well pad must be provided upon

request to the Department, there appears to be no direct oversight of the record keeping or

compliance inspection schedule. It is not clear how often, if at all, the drillers records will be

checked for accuracy. United States Fish and Wildlife recommends that the proposed regulations

be revised to provide for regular inspection of these records by the Department. This will provide

a check and balance approach to ensure that appropriate information is collected and proper

procedures are being followed.

Response 5880:

The revised regulations at 6 NYCRR 750-3 include an appropriate level of monitoring

requirements, which detail HVHF operations from the amount of water used for well stimulation

through the ultimate disposition of any HVHF wastewater. The Department anticipates

conducting inspections for compliance with regulations and permit conditions, including

monitoring requirements.

Comment 5881:

All wastewater must be measured and tracked offsite to a disposal facility according to the

proposed regulations in Section 750-3.13 (g). Flowback water must be tested for naturally

occurring radioactive materials and chemical composition. Again, the proposed regulations do

not require submittal of this data to the Department unless requested. United States Fish and

Wildlife recommends that these data be compiled in a database where the Department has a

permanent record and can reference the information quickly, if needed. The information could be

submitted through a secure internet site to protect sensitive information but be accessible to

relevant agencies. This database could also contain records of drinking water wells located in the

vicinity of gas well drilling activity. United States Fish and Wildlife believes this information

would assist the Department in understanding the chemical composition of flowback water and

determine if effective disposal methods are being employed.

Response 5881:

See Responses to Comment 3441 regarding the Fluid Disposal Plan, Comment 3781 regarding

headworks analysis, Comment 5874 regarding waste tracking, and Comment 3909 regarding

testing protocol.

Comment 5882:

Many requirements are listed in Section 750-3.21 for a Stormwater Pollution Discharge

Elimination System General Permit. The general permit is not eligible for projects which affect a

listed or proposed threatened or endangered species or its designated critical habitat. This section

of the draft regulations is not clear because it is not stated whether this language refers to State

and/or Federally-listed species. As United States Fish and Wildlife stated in our current

comments on the rdSGEIS, the Department should include provisions in the permit application

process and regulations which require an applicant or sponsor of a drilling site to contact our

office to determine if Federally-listed species could be affected by a proposed gas well.

Response 5882:

"Endangered Species" is defined in 6 NYCRR Part 182.2 as follows: (e) 'Endangered species'

are species that: (1) are native species in imminent danger of extirpation or extinction in New

York based on the criteria for listing in section 182.3(b) of this Part and that are listed as

endangered in subdivision (a) of section 182.5 of this Part; or (2) are species listed as endangered

by the United States Department of the Interior in the Code of Federal Regulations (50 CFR part

17).

Comment 5886:

The high-volume hydraulic fracturing State Pollutant Discharge Elimination System permit is an

individual permit that in itself requires a State Environmental Quality Review determination as

identified in paragraph 750-3.6(b)(1).

Response 5886:

That language has been removed from the revised regulations at 6 NYCRR 750-3. The revised

regulations provide that “[w]here required, all necessary department permits subject to the

Uniform Procedures Act have been obtained, unless the department determines otherwise

pursuant to paragraph 621.(3)(a)(4) of this Title.”

Comment 5888:

Requirements for Publicly Owned Treatment Works shouldn't be in Part 750-3.12. Their

inclusion makes the regulation confusing; they are not germane to the disposal of flowback water

by a high-volume hydraulic fracturing well. Federal regulations are improperly cited in this

section as materials incorporated by reference (see Part 750-1.24 of this Title) should appear

after each reference.

Response 5888:

POTWs are potential options for the disposal of HVHF wastewater provided the requirements of

revised regulations at 6 NYCRR 750-3.12 are satisfied. See also Response to Comment 3781

regarding a headworks analysis.

Comment 5890:

The Beneficial Use Determination is a Solid Waste Program. This paragraph 750-3.12(d)(6), if

adopted, should be in Part 360-1.15 and cross referenced in Part 750-12.3(d)(6).

Response 5890:

See Response to Comment 3898 regarding BUDs.

Comment 5892:

The high-volume hydraulic fracturing Storm Water Pollution Prevention Plan with additives to

be provided and with the permit application should be taken as general. Operators cannot specify

service companies and additives prior to the permit and expect to pump those additives specified

during the stimulation. Furthermore, operations on the well may dictate a treatment change

during the course of performing work. Flexibility should be allowed regarding chemicals and

additives to be used.

Response 5892:

The revised regulations at 6 NYCRR 750-3 require “The owner or operator must ensure that the

Comprehensive SWPPP is implemented. This includes any changes made to the Comprehensive

SWPPP.” This would include any modifications to the chemicals used on site.

Comment 5893:

6 NYCRR Part 750-12.3(d)(6) states: (6) The provisions below apply to disposal of production

brine in accordance with the terms of a Department-approved Beneficial Use Determination.

Production brine may be disposed in accordance with the terms and conditions of a Department-

approved Beneficial Use Determination. In addition to the requirements listed in 6 NYCRR Parts

360 and 364, the following information shall also be presented as part of the application for the

Beneficial Use Determination: radiologic limits; contaminant limits; and operational

requirements such as maximum brine application frequency and maximum brine application rate.

Comment: This is a Solid Waste Program. If adopted, should be in Part 360-1.15 and Part 364.




Comment 5895:

The NYCRR should be revised at 6 NYCRR 750-3.3, 6 NYCRR 750-3.2, 6 NYCRR 553.2, and

6 NYCRR 560.4 to provide consistent setback requirements that are protective of water sources,

including rivers, streams, lakes, and private water supplies.

Response 5895:

See Response to Comment 2453 regarding setbacks. Duplication and consistency have been

addressed, including cross-references in the revised 6 NYCRR 750-3 to the revised 6 NYCRR

Parts 550-556 and 560, where appropriate.

Comment 5898:

6 NYCRR 750.3.3 should be amended to require a 5,000 foot setback from the closest edge of a

wellpad to any public or private water well and domestic water supply springs.

Response 5898:

See Responses to Comment 2453 regarding setbacks, and 3784 regarding private water well

testing.

Comment 5899:

For multi-well pads and high-volume hydraulic fracturing well pads, the site disturbance

associated with such operations should be separated by a 5,000 foot buffer from the boundary of

any state forest, state park or wildlife management area. This would require an amendment of the

currently proposed language of 6 NYCRR Sections 560 and 6 NYCRR 750-3-3.

Response 5899:

This comment, regarding setbacks from state forest, state parks and wildlife management areas,

is outside the scope of the revised regulations at 6 NYCRR 750-3. However, see Response to

Comment 2453 regarding setbacks from water resources. See also Response to Comment 5726

in Category 92 (Part 190). The Department’s regulatory prohibition on surface disturbances

associated with high-volume hydraulic fracturing on reforestation lands and wildlife

management areas is based in part upon the unique legislative and legal constraints that apply to

these State-owned lands. Private lands buffering State-owned lands are not subject to the same

legal constraints and legislative protections afforded to these State-owned lands. Despite this,

the Department recognized concerns regarding potential unmitigated impacts to terrestrial

habitats and permit conditions may be imposed pursuant to the draft SGEIS to protect habitats of

utmost concern in New York, namely large blocks of forests and grasslands that support

declining species that may be located on buffer lands identified in this comment.

Comment 5903:

As a result of recent storm events, when the Departments floodplain maps are updated, 6

NYCRR Sections 500 and 750.3 should be amended to prohibit high-volume hydraulic

fracturing within 200-year floodplains.

Response 5903:

See Response to Comment 2453 regarding setbacks from water resources generally. Note that

the revised regulations include an increased setback of 300 feet from perennial or intermittent

streams, as described in Parts 800-941 of this Title, storm drains, lakes, or ponds. HVHF

operations within this setback would not be eligible for coverage under a stormwater general

permit for HVHF operations, and thus, would require an individual SPDES permit and a site-

specific SEQRA review.

Comment 5906:

The regulatory buffer between any wetland identified and protected as a wetland under New

York States Freshwater Wetlands Program should be not less than 750 feet from the edge of the

well pad to the wetland area and all well pads proposed to be located between 750 and 1,500 feet

from said wetland should be subject to a site-specific State Environmental Quality Review Act

review. The proposed language of 6 NYCRR sections 560 and 750.3 should be amended

accordingly.

Response 5906:


Comment 5909:

Part 750-3.21(g) lists activities that are ineligible for coverage under the general permit, but may

be eligible for coverage under an individual State Pollutant Discharge Elimination System

permit. These proposed activities include construction of a centralized open air flowback

impoundment, construction of high-volume hydraulic fracturing on steep slopes, high-volume

hydraulic fracturing operations at certain depths of hydraulic fracturing and high-volume

hydraulic fracturing operations within certain buffers to water resources. Adirondack Mountain

Club strongly opposes all of these proposed variances from Part 750-3.21 standards which were

designed to protect New York States surface and groundwater resources. 750-3-21(a) must be

amended to preclude these high-volume hydraulic fracturing activities under any and all

circumstances.

Response 5909:

HVHF operations within these setbacks would not be eligible for coverage under a stormwater

general permit for HVHF operations, but would require an individual SPDES permit and a site-

specific SEQRA review. That process would be subject to public participation, and would

potentially include additional mitigation measures or requirements.

Comment 5910:

Part 750-3.21 should be amended to prohibit an applicant from proposing a well pad within

2,000 feet of a principal aquifer because the groundwater table in the principal aquifers is

overlain with sand and gravel and generally ranges from zero to 20 feet below the ground.

Because these aquifers are often located in unconsolidated sand and gravel deposits, the high

permeability of soils that overlie principal aquifers and shallow depth to the water table make

these aquifers highly vulnerable to contaminations from spills, accidents, and

wastewater/produced water overflows of high-volume hydraulic fracturing operations. The 500

foot buffer proposed in the SGEIS is woefully inadequate and must be replaced by the said 2,000

foot buffer.

Response 5910:

See Responses to Comment 3785 regarding Principal Aquifers and Comment 2453 regarding

setbacks generally. HVHF operations within 500 feet of a Principal Aquifer would not be

eligible for coverage under a stormwater general permit for HVHF operations, but would require

an individual SPDES permit and a site-specific SEQRA review. That process would be subject

to public participation, and would potentially include additional mitigation measures or

requirements.

Comment 5911:

6 NYCRR Part 750 should be amended to require a buffer of no less than 2,000 feet between a

well pad and the edge of a principal or primary aquifer.

Response 5911:


Comment 5914:

750.1 and 750.3: General Comment Pertaining to Disposal of All Wastes from Hydraulic

Fracturing Operations: Flowback and production brine should be treated and disposed of as

hazardous waste, or maintained in tanks. They should not be treated at any publicly owned

treatment works and treated wastes should never be released to the environment, nor should any

of them or their derivatives be put in a landfill. (This change should also be included in 750-3.4

(b) (1-2), 750-3.11 generally, and 750-3.11 (f)).

Response 5914:

See Responses to Comment 3781 regarding headworks analyses, and Comment 3441 regarding

Fluid Disposal Plans. Currently, “drilling fluids, produced waters, and other wastes associated

with the exploration, development, or production of crude oil, natural gas or geothermal energy”

are excluded from being regulated as a hazardous waste in both federal law and federal and state

regulations (42 U.S.C. 6921 (b)(2)(A), 40 CFR 261.4(b)(5), 6 NYCRR 371.1(e)(2)(v)). This is

commonly referred to as the “extraction and production” (E&P) exclusion. This exclusion has

existed since the beginning of the RCRA regulatory program and was included verbatim in the

New York regulations when USEPA delegated the RCRA program to New York. The exclusion

was conditionally included in the RCRA statute by Congress (Section 3001(b)(2)(A)). Congress

required USEPA to study these wastes and determine whether they should be regulated as

hazardous waste or not. USEPA reported to Congress in 1988 and concluded that regulation of

E&P wastes as hazardous waste was not warranted. USEPA provided several reasons for their

conclusion (53 FR 25446):

existing state and federal regulatory programs (including the Solid Waste Disposal Act,

Safe Drinking Water Act, Clean Air Act, and Oil Pollution Act) provided adequate

controls for the disposal of these wastes;

given that billions of barrels (volumes approaching one trillion gallons per year) of these

wastes are generated per year nationally, regulating these wastes under RCRA would

cause a severe impact on oil and gas production in the United States;

insufficient commercial treatment capacity would create serious short-term

implementation problems; and

regulating these wastes under RCRA would inhibit the exploration for new oil, gas, and

geothermal energy deposits.

The revised regulations and draft HVHF GP include provisions to prevent significant adverse

impacts from mismanagement of high-volume hydraulic fracturing wastes. Wastes must be

handled and stored in ways to minimize the potential for releases (e.g., secondary containment

for flowback fluids; drilling operations must conform to setback requirements; transportation

must be carried out by haulers permitted under Part 364; the disposal of wastes must be tracked

from generation to disposal using a Drilling and Production Waste Tracking Form; and disposal

of waste fluids must be in accordance with a variety of requirements, particularly those under

SPDES.

Regulating high-volume hydraulic fracturing wastes as hazardous wastes would unnecessarily

increase the cost of regulation with little, if any, additional environmental benefit. It would also

likely eliminate the recycling of flowback water. The revised regulations at 6 NYCRR

554.1(c)(1) requires that the owner or operator must state in its plan that it will maximize the

reuse and/or recycling of used drilling mud, flowback water and production brine, to the

maximum extent feasible.

Comment 5923:

750-3.4 (b) (5): 45 days should be reduced to two weeks.

Response 5923:

See Response to Comment 5867 regarding the 45-day requirement.

Comment 5926:

750-3.4 (b): No alternative plans should be allowed.

Response 5926:

The requirements related to alternative plans has been removed from the revised regulations at 6

NYCRR 750-3.

Comment 5929:

750-3.4 (b) (4) Nothing but fresh water should ever be allowed in any pits, with no exceptions.

Response 5929:

The revised regulations at 6 NYCRR 750-3 require that “A closed-loop tank system must be

used instead of a reserve pit to manage drilling fluids and cuttings, in cases set forth in paragraph

6 NYCRR 560.6(c)(7), as adopted on XX, 20XX.” A closed-loop system is required for

horizontal drilling in the Marcellus Shale unless an acid rock drainage mitigation plan for on-site

burial of such cuttings is approved by the department; and any drilling requiring cuttings to be

disposed of off-site.

Comment 5930:

750-3.4 (b) (6) No alternative plans should be allowed.

Response 5930:


Comment 5932:

750-3.4 (b) (8): Only non-toxic chemicals should be allowed in hydraulic fracturing. If drilling

cannot be done without toxins, it should not be done at all.

Response 5932:

See Response to Comment 3438 regarding the alternatives analysis.

Comment 5933:

Part 750.3.21 (l) (2) (2) should be amended as follows: In the event a new high-volume hydraulic

fracture (HVHF) general permit is not issued prior to termination of the current HVHF general

permit, [and where no modifications have been made pursuant to the current HVHF general

permit], then the owner or operator may continue to operate and discharge in accordance with the

terms and conditions of the current HVHF general permit until such time as a new HVHF

general permit is issued.

Response 5933:

The draft regulations at 6 NYCRR 750-3 did not contain the language “and where no

modifications have been made pursuant to the current HVHF general permit.” The revised

regulations at 6 NYCRR 750-3 state “In the event a new HVHF general permit is not issued prior

to termination of the current HVHF general permit, the owner or operator may continue to

operate and discharge in accordance with the terms and conditions of the current HVHF general

permit until such time as a new HVHF general permit is issued.”

Comment 5936:

750-3.11 (i) Any other allowable tank materials should be written into the regulation right now

and here and the public given another chance to comment on them. They should not be left to the

Departments discretion.

Response 5936:

Flexibility in the revised regulations at 6 NYCRR 750-3 is necessary to allow for improvements

in technology, but the regulations do require that the tanks must be covered and watertight. See

also Response to Comment 3903 regarding materials storage.

Comment 5941:

750-3.12 (b) All Fluid Disposal Plans should be fully disclosed to the public, with nothing held

back. All ingredients of all products with Chemical Abstracts Service numbers should be

disclosed, as well as results from testing for heavy metals, total dissolved solids, and

radioactivity, which should be required. This information should be posted on the Department

website by well, at least three days before the fluid will be disposed of, accessible to the general

public.

Response 5941:

See Response to Comment 3441 regarding Fluid Disposal Plans.

Comment 5942:

The proposed regulations are not clear and coherent as required by law. They do not provide the

operators, monitors or the public with a clear indication of what is allowed and what is

prohibited. The regulations need to be more clearly defined in order to be properly interpreted

and withstand the scrutiny and challenges that will be presented by the lawyers and operators of

drilling and energy companies.

Response 5942:

The regulations at 6 NYCRR 750-3 have been revised in terms of organization and for clarity.



Comment 5943:

750-3.12 (d) (1) (iv): No State Pollutant Discharge Elimination System permits should be

modified to accommodate flowback or production brine. It should be taken to a certified

hazardous waste disposal site.

Response 5943:

See Response to Comment 5914 regarding hazardous waste.

Comment 5945:

750-3.12 (d) (1) (vi): This section should read that the publicly owned treatment works is capable

of completely removing the contaminants.

Response 5945:

That language has been changed in the revised regulations at 6 NYCRR 750-3. See Response to

Comment 3781 regarding headworks analyses. The revised regulations at 6 NYCRR 750-3 state

“The headworks analysis must demonstrate that the HVHF wastewater will not cause a violation

of the POTW's effluent limits or sludge disposal criteria, and will not result in pass through of

substances present in HVHF wastewater, or adversely affect the POTW's treatment processes.”

Comment 5946:

750-3.12 (d) (4 through 6): No injection well disposal of hydraulic fracturing waste should be

allowed in New York State because they can cause earthquakes, which the public should not be

subjected to.

Response 5946:

The comment is outside the scope of the regulations. A SPDES permit is required for deep well

inject, and with that permitting process, a site-specific SEQRA review would be conducted.

However, the revised regulations at 6 NYCRR 750-3 do contain the requirements to obtain a

SPDES permit for deep well injection. A geotechnical survey is required by the revised

regulations at 6 NYCRR 750-3 to ascertain the ability of the disposal strata to accept and retain

the injected fluid will include an analysis of any known faults in the area. The Department

characterizes the risks of earthquakes from high-volume hydraulic fracturing and deep well

injection as extremely low and concludes there is essentially no increased risk to the public,

infrastructure or natural resources from induced seismicity.

Comment 5948:

750-3.12 (d) (7): No other disposal options should be allowed unless they are set out in detail in

these regulations and the public has a chance to comment on them in a later comment session.

Response 5948:

See Response to Comment 3441 regarding Fluid Disposal Plans. The revised regulations at 6

NYCRR 750-3 no longer contain an explicit statement that other disposal options can be

proposed. The revised regulations at 6 NYCRR 750-3 do not choose a disposal option and do

not encourage one suitable disposal option over another. The revised regulations at 6 NYCRR

750-3 provide the requirements for each of the options to be approved by the Department and

where appropriate requirements on the well owner or operator for disposal of HVHF wastewater.

Comment 5950:

750-3.13: All of this information under (b), (c), (d), (e), (f), (g) should be posted on the

Department website within a week of its occurrence (or at a reasonable interval - such as

monthly - for continuous measures), readily available to the public without special request.

Response 5950:

All documents submitted to the Department would be available to the public, subject to the

limitations of the Freedom of Information Law. Additionally, the draft HVHF GP contains the

following “The NOI, SWPPP and inspection reports required by this general permit are public

documents that the owner or operator must make available for review and copying by any person

within five (5) business of the owner or operator receiving a written request by any such person

to review the NOI, SWPPP or inspection reports. Copying of documents will be done at the

requester’s expense.”

Comment 5951:

750-3.12 (h): All water wells within one mile should be tested to allow for a margin of error.

Response 5951:

The revised regulations at 6 NYCRR 750-3 state “[t]he owner or operator must conduct

residential water well testing in accordance with the requirements of subdivision 560.5(d) of this

Title, as adopted on XX, 20XX, except that copies of test results and documentation related to

delivery of test results to owners of water wells must be sent to the NYSDOH.” Additionally,

“[t]he department may require that an approvable groundwater monitoring program be developed

and implemented.”

Comment 5953:

750-3.12 (i): Results of all water tests must be made available to the public so they can track

contamination events and neighbors can be alerted. This information is vital to public health and

must not be kept secret.

Response 5953:

See Response to Comment 5951 regarding residential water well testing and groundwater

monitoring. All documents submitted to the State would be available to the public, subject to the

limitations of the Freedom of Information Law.

Comment 5954:

750-3.14 (c): No time interval for compliance should be allowed. No discharge should be

allowed if standards set are not being met.

Response 5954:

The revised regulations at 6 NYCRR 750-3 no longer specify additional requirements for

waterbodies with approved TMDLs. A SPDES permit issued for high-volume hydraulic

fracturing will address compliance with any applicable TMDLs.

Comment 5955:

750-3.21 (g): Please set out specific criteria (other than information lacking) under which permits

will be denied or accepted. These regulations present a long list of required information, but not

how permits will be treated based on the information presented. The public needs to know very

specifically what the company will and will not be allowed to discharge, and where.

Response 5955:

If a discharge is eligible for coverage under a stormwater general permit for HVHF operations,

then coverage will be effective after a specified time period. There is no acceptance or denial by

the Department regarding coverage under a general SPDES permit. Further details about general

permit coverage are contained in the draft HVHF GP. However, there are regulatory

requirements that would allow the Department to require an individual SPDES permit instead of

a general SPDES permit. The revised regulations at 6 NYCRR 750-3 state “(1) As set forth in

subdivision 750-1.21(e) of this Part, the department may require any owner or operator

authorized to discharge in accordance with an HVHF general permit to apply for and obtain an

individual SPDES permit or apply for authorization to discharge in accordance with another

general permit. (2) The department may suspend, terminate, or deny an owner’s or operator’s

coverage under an HVHF general permit if the department determines that the Comprehensive

SWPPP does not meet any HVHF general permit requirements.”

Comment 5957:

750-3.21 (n): All suspensions, terminations, stop work orders, and findings of non-compliance

must be posted on the Departments website and made accessible to the public without request

within three days.

Response 5957:

The comment does not provide the legal basis for this requirement. All documents within the

Department’s possession would be available to the public, subject to the limitations of the

Freedom of Information Law.

Comment 5958:

750-3.21 (l) (2): No continuance of discharge should be allowed before a permit is renewed.

Since the Department has promised not to proceed until the Department staffing is adequate, this

should never be a problem, and all permits should be either renewed or rejected on time.

Response 5958:

Section 401 of the State Administrative Procedure Act (SAPA) allows a permit to be continued

where there has been a timely and sufficient application for renewal. This would apply to both

general and individual SPDES permits. For a general SPDES permit, no new dischargers would

be allowed to obtain coverage under any SAPA-extended general SPDES permit.

Comment 5959:

750-3.21 (l) (1): The permit should be required to be renewed every year. Cumulative discharges

of pollutants in an area may increase dramatically as numerous wells are dug, so the discharge

limits for pollutants should at least be re-evaluated every year.

Response 5959:

New York State law and regulation allow SPDES permits for discharges to surface waters to be

issued for up to five years. ECL §70-0117, as well as 6 NYCRR 750-1.21, address the use of

SPDES general permits. The revised regulations at 6 NYCRR 750-3 also address a SPDES

general permit for high-volume hydraulic fracturing. High-volume hydraulic fracturing

operations are appropriately regulated through a general permit because they (1) involve the

same or substantially similar types of operations; (2) discharge the same types of pollutants; (3)

require the same effluent limitations or operating conditions; (4) require the same or similar

monitoring; and (5) will result in minimal adverse cumulative impacts. As high-volume

hydraulic fracturing operations are generally consistent from well site to well site, utilizing

similar industrial processes and materials, the Department has determined that a general permit

adequately addresses potential sources of contamination of water resources from high-volume

hydraulic operations when a well site is operated in accordance with general permit conditions,

and in compliance with monitoring, reporting and SWPPP requirements.

Comment 5963:

The Department should build, over time, a list of "Alternative Chemical Addition" products that

have been deemed appropriate to meet the criteria of Proposed 750-3.4(B)(7) and (8), thereby

creating an incentive of a streamlined application process if chemical additives on this list are

used.

Response 5963:

See Response to Comment 3438 regarding the alternatives analysis. The Department agrees that

streamlining the application process is positive. A list of alternative chemical additives may be

included in guidance related to that analysis.

Comment 5964:

The requirements of 750-3.12 (D) should also apply to spreading of produced brine on the roads.

Response 5964:


Comment 6060:

Subpart 750-3, (high-volume hydraulic fracturing) 730-3.3 Prohibited Activities and Discharges:

"All distances noted below are measured from the closest edge of the [high-volume hydraulic

fracturing] well pad to provide a margin of safety.... (2) within 500 feet of, and including a

primary aquifer; ... (4) within 2,000 feet of any public (municipal or otherwise) water supply,

including wells, reservoirs, natural lakes or man-made impoundments, and river or stream

intakes." There appears to be an inconsistency with the statements above in 750-3.3 with the

statements that follow in 750-3.21. 750-3.21 high-volume hydraulic fracturing State Pollutant

Discharge Elimination System General Permits: "(f) The following are not authorized by the

[high-volume hydraulic fracturing State Pollutant Discharge Elimination System] general permit:

... (4) [high-volume hydraulic fracturing] operation sited within the following buffers (calculated

from the closest edge of the gas well pad): [The following is provided in table format in the OCR

comment] Principal Aquifer (500 feet); Private Water wells (500 feet); Wetland (100 feet);

Storms, drains, lakes, or ponds, and perennial or intermittent streams, as described in 6 NYCRR

Parts 800-910 P (150 feet); Perennial or intermittent streams as described in 6 NYCRR Parts

800-910, and that are tributary to surface public drinking water supplies (500 feet)" The

inconsistency does not state in the table "within 2,000 feet of any public (municipal or otherwise)

water supply, including wells, reservoirs, natural lakes or man-made impoundments, and river or

stream intakes."

Response 6060:

See Response to Comment 2453 regarding setbacks generally. There are two different

provisions in the regulations-one is for prohibitions and the other is for where HVHF operations

are ineligible for coverage under a general permit.

Comment 6815:

The following sections should be deleted: Section 750-3.12 (b); Section 750-3.12 (c); Section

750-3.21 (f) (3); Section 750-3.21 (f) (4); Section 750-3.21 (f) (9); Section 750-3.21 (f) (10); and

Section 750-3.21 (o).

Response 6815:

The revised regulations at 6 NYCRR 750-3 have been revised for organization and for clarity.

Additionally, duplication and consistency have been addressed, including cross-references in the

revised 6 NYCRR 750-3 to the revised 6 NYCRR Parts 550-556 and 560, where appropriate.

Comment 6819:

Subdivision (g) should be revised to state: (g) High-volume hydraulic fracturing operations, as

defined in Section 750-3.2, do not require a permit for the stimulation process itself, but the

construction and operation of a well pad and access road require either an individual State

Pollutant Discharge Elimination System permit in accordance with Subpart 750-3 or a general

permit in accordance with subpart 750-3.21.

Response 6819:

The revised regulations at 6 NYCRR 750-3 no longer contain the specific language in (g).

However, a SPDES permit is required for HVHF operations, which includes the Construction

Phase, HVHF Phase and Production Phase.

Comment 6824:

The definitions in Section 750-3.2 should be revised to state: (1) Comprehensive Stormwater

Pollution Prevention Plan means the combined Construction Stormwater Pollution Prevention

Plan and high-volume hydraulic fracturing Stormwater Pollution Prevention Plan. (2)

Construction phase means the construction of access roads, well pad, and other appurtenances.

(3) Construction Stormwater Pollution Prevention Plan means the stand alone stormwater

pollution prevention plan that includes best management practices and other requirements to

control the pollution of stormwater during construction and post-construction. (4) Drilling High-

Volume Hydraulic Fracturing Phase (Drilling and high-volume hydraulic fracturing Phase)

means 1) the phase between the construction project completion and the Production Phase; and

2) any subsequent well drilling, stimulation or re-stimulation event on the same well pad. This

includes well drilling, high-volume hydraulic fracturing, well stimulation and on-site handling

and treatment of return flow. (5) High-Volume Hydraulic Fracturing Operations (high-volume

hydraulic fracturing Operations) means: (i) Construction Phase; (ii) Drilling and high-volume

hydraulic fracturing Phase; and (iii) the Production Phase. (6) high-volume hydraulic fracturing

general permit means a State Pollutant Discharge Elimination System permit issued pursuant to

section 750-3.21 of this Part. (7) high-volume hydraulic fracturing State Pollutant Discharge

Elimination System permit means an individual or general State Pollutant Discharge Elimination

System permit for high-volume hydraulic fracturing activities. (8) high-volume hydraulic

fracturing Stormwater Pollution Prevention Plan means the stormwater pollution prevention plan

required by a State Pollutant Discharge Elimination System permit that includes structural and

non-structural best management practices and other requirements to control the pollution of

stormwater during the Drilling and high-volume hydraulic fracturing Phase and the Production

Phase. (9) Production phase means the phase after the Drilling and high-volume hydraulic

fracturing Phase through termination of coverage under the high-volume hydraulic fracturing

general permit. This phase begins when the Drilling and high-volume hydraulic fracturing phase

has been completed for all wells planned for that well pad and partial site reclamation has been

completed.

Response 6824:

Several changes have been made to the definitions in the revised regulations at 6 NYCRR 750-3

for organization and/or clarity within the regulations. Several changes have also been made to

the definitions in the revised regulations at 6 NYCRR 750-3 to eliminate redundancy with and/or

for consistency with the revised draft regulations at 6 NYCRR Parts 550-556 and 560, where

appropriate. See the revised regulations at 6 NYCRR 750-3 for specific changes to the

definitions in the comment.

Comment 6826:

All text in Part 750-3.3, Prohibited Activities and discharges, should be deleted.

Response 6826:

The revised regulations at 6 NYCRR 750-3 continue to include the prohibited activities and

discharges. The Department believes it is necessary to include the prohibitions in the regulations

to protect the specified water resources. The comment does not provide any basis for removing

that section of the regulations.

Comment 6828:

750-3.6 should be revised to state: The requirements in this section are in addition to those listed

in section 750-1.6. (a) Prior to obtaining an individual high-volume hydraulic fracturing State

Pollutant Discharge Elimination System permit, an owner or operator must first develop a

Comprehensive Stormwater Pollution Prevention Plan, which includes both the Construction

Stormwater Pollution Prevention Plan and high-volume hydraulic fracturing Stormwater

Pollution Prevention Plan. (b) All of the following criteria must be satisfied in order for an owner

or operator to obtain an high-volume hydraulic fracturing State Pollutant Discharge Elimination

System permit: (1) Project review pursuant to State Environmental Quality Review Act has been

satisfied, where applicable; (2) Where required, all necessary Department permits subject to the

Uniform Procedures Act have been obtained, unless otherwise notified by the Department

pursuant to Part 621 of this Title; and (3) A complete Notice of Intent, which contains the well

permit American Petroleum Institute number, has been submitted to the Department by the

owner or operator.

Response 6828:

The revised regulations at 6 NYCRR 750-3 with respect to individual SPDES permit

requirements have been re-written. Several changes have been made for organization and/or

clarity within the regulations. Several changes have also been made to eliminate redundancy

with and/or for consistency with the revised draft regulations at 6 NYCRR Parts 550-556 and

560, where appropriate. See the revised regulations at 6 NYCRR 750-3 for specific changes in

the comment.

Comment 6829:

Section 750-3.11 should be revised to state: The regulations in this section are in addition to

those listed in section 750-1.11. (a) The Construction Stormwater Pollution Prevention Plan shall

include erosion and sediment control practices designed in conformance with the Department's

technical standards (750-3.24 of this Part) or the equivalent. (b) The owner or operator must

ensure that all erosion and sediment control practices and all post-construction stormwater

management practices identified in the Construction Stormwater Pollution Prevention Plan are

maintained in effective operating condition at all times. (c) The owner or operator must ensure

that, where post-construction stormwater management practices are required, such practices are

operated and maintained until the Notice of Termination is submitted to the Department. (d) The

high-volume hydraulic fracturing Stormwater Pollution Prevention Plan must, at a minimum,

include the high-volume hydraulic fracturing Stormwater Pollution Prevention Plan General

Requirements listed in subparagraph (1) below, Structural Best Management Practices, Non-

structural BMPs, and Activity-Specific Stormwater Pollution Prevention Plan Requirements. (1)

The following conditions apply to all owners or operators of high-volume hydraulic fracturing

operations: (i) Construction Project Completion - The owner or operator shall, prior to

commencing the Drilling and high-volume hydraulic fracturing Phase, (a) develop and

implement measures to ensure all construction activities identified in the Construction

Stormwater Pollution Prevention Plan have been completed, (b) ensure that all areas of

disturbance have been stabilized, (c) ensure that all temporary, structural erosion and sediment

control measures have been removed (unless they are still being utilized as part of the

stabilization process), and (d) ensure that all post-construction stormwater management practices

have been constructed in conformance with the Construction Stormwater Pollution Prevention

Plan and are operational. (e) The owner or operator must have a Spill Prevention Control and

Countermeasure Plan on-site through all phases of the high-volume hydraulic fracturing

operation (Construction Phase, Drilling and high-volume hydraulic fracturing Phase, and

Production Phase). The Spill Prevention Control and Countermeasure Plan must include an

explanation of existing or planned material handling procedures, storage requirements, secondary

containment, and equipment (e.g., diversion valves), that are intended to minimize spills or leaks

at the site. Measures for cleaning up spills or leaks must be consistent with the procedures for

petroleum bulk storage, chemical bulk storage or hazardous waste management in the

Environmental Conservation Law and implementing regulations. Quantities and types of

equipment specified in the Spill Prevention Control and Countermeasure Plan shall be present on

site at all times.

Response 6829:

The revised regulations at 6 NYCRR 750-3 with respect to the application of standards,

limitations and other requirements have been re-written. Several changes have been made for

organization and/or clarity within the regulations. Several changes have also been made to

eliminate redundancy with and/or for consistency with the revised draft regulations at 6 NYCRR

Parts 550-556 and 560, where appropriate. See the revised regulations at 6 NYCRR 750-3 for

specific changes in the comment.

Comment 6832:

The title of section 750-3.12 should be revised to Disposal of high-volume hydraulic fracturing

produced water.

Response 6832:

The revised regulations at 6 NYCRR 750-3 must address the disposal of all wastewater

associated with high-volume hydraulic fracturing. Therefore, the title is correct. The revised

regulations at 6 NYCRR 750-3 refer to “HVHF wastewater,” which is defined in the revised

regulations as “liquid waste consisting of one or more of the following: drilling fluids, formation

fluids, flowback, or production brine.”

Comment 6833:

Section 750-3.12 (a) should be revised to state: (a) The high-volume hydraulic fracturing

permittee must demonstrate that all produced water generated by the facility will be treated,

recycled, or otherwise properly disposed for a period of time not less than five years for the date

the well is spud. Once active high-volume hydraulic fracturing operations at the site have ceased

and the gas well(s) are in the production phase, the permittee must continue to properly collect

and dispose of all produced water generated at the site.

Response 6833:

See Response to Comment 6832 regarding wastewater associated with high-volume hydraulic

fracturing. The revised regulations at 6 NYCR 750-3 state “All HVHF wastewater must be

treated, recycled, or otherwise properly disposed through the life of the well in accordance with

all applicable federal and state laws.” See also Response to Comment 3441 regarding the Fluid

Disposal Plan.

Comment 6834:

Section 750-3.12 (d) should be revised to state: The disposal options for produced water are

listed below.

Response 6834:


fracturing.

Comment 6835:

Section 750-3.12 (1) should be revised to state: (1) The provisions listed below apply to offsite

disposal at publicly owned treatment works located within New York State:

Response 6835:

The revised regulations at 6 NYCRR 750-3 only apply to activities within New York State so

that the suggested additional language is already implied.

Comment 6836:

Section 750-3.12(1)(v) should be revised to state: (v) Produced water from flowback operations

and water produced during the production phase from wells permitted pursuant to this Part may

be accepted by publicly owned treatment works only where such publicly owned treatment

works have approved pretreatment or mini-pretreatment programs in subparagraphs (iii) and (iv)

of this paragraph.

Response 6836:


fracturing. The revised regulations at 6 NYCRR 750-3 provide that “HVHF wastewater may be

accepted only by a POTW that has a valid SPDES permit and a pretreatment program approved

by EPA or a mini-pretreatment program approved by the department, and is permitted by the

department to accept HVHF wastewater.”

Comment 6837:

Section 750-3.12(1)(vi) should be revised to state: (vi) Prior to being allowed to accept produced

water including water produced during flowback operations, the publicly owned treatment works

must perform a headworks analysis for this wastewater source and submit such analysis to the

Department and United States Environmental Protection Agency for approval. Such wastewater

may only be accepted by the publicly owned treatment works if the headwords analysis meets

the requirements of 40 CFR Part 403 and the State Pollutant Discharge Elimination System

permit for such publicly owned treatment works. The headworks analysis must demonstrate,

among other things, that the publicly owned treatment works is capable of removing the

contaminants expected to be present in the produced water, including but not limited to Total

Dissolved Solids, naturally occurring radioactive materials, barium, bromides, benzene, toluene,

ethylbenzene, xylene, and chemicals present in the additives used in the development of the

wells. The headworks analysis process includes the following steps: (a) upon submittal and

approval of the headworks analysis, the Department may modify the publicly owned treatment

works State Pollutant Discharge Elimination System permit to include appropriate monitoring

and effluent limits for this wastewater source. The State Pollutant Discharge Elimination System

permit for the publicly owned treatment works shall include specific discharge limitations and

monitoring requirements, including routine reporting of monitoring results; (b) The Department's

procedures for publicly owned treatment works acceptance of high-volume hydraulic fracturing

wastewater discharges are detailed in Division of Water Guidance Document 1.3.8.1, Guidance

for Acceptance of high-volume hydraulic fracturing Wastewater by publicly owned treatment

works; (c) The permittee may discharge produced water from either flowback operations or the

production phase to the headworks of a publicly owned treatment works only if such publicly

owned treatment works has undertaken an approved headworks analysis and modified its State

Pollutant Discharge Elimination System permit in accordance with subparagraphs (i) - (viii) of

this paragraph. Each discharge of produced water to the headworks of the publicly owned

treatment works shall include the following documentation: 1. The manifest stating the source

well of the wastewater, the identity of the high-volume hydraulic fracturing permittee, and all

products used in the hydrofracturing of the well; 2. The volume of wastewater to be discharged;

and 3. An assay of the concentrations of high-volume hydraulic fracturing chemicals present,

including total dissolved solids, naturally occurring radioactive materials, benzene, toluene,

ethylbenzene, and xylene.

Response 6837:

The section of the regulations at 6 NYCRR 750-3 regarding disposal at a POTW has been re-

written for clarity and organization. See the revised regulations at 6 NYCRR 750-3 for specific

changes in the comment. References to guidance documents have been removed from the

revised regulations at 6 NYCRR 750-3.

Comment 6843:

Section 750-3.12(1)(vii) should be revised to state: Section (vii) Should the publicly owned

treatment works meet all requirements of this subpart, any produced water treated by such

publicly owned treatment works must be introduced to the headworks of the publicly owned

treatment works and receive full treatment unless otherwise expressly approved by the

Department. The introduction to Section 750-3.12(2) should be revised to state: (2) The

provisions below apply to offsite disposal at privately owned industrial treatment facilities

located within New York State:

Response 6843:


fracturing. The revised regulations at 6 NYCRR 750-3 state “[a]ny HVHF wastewater to be

treated by the POTW must be introduced to the headworks of the POTW, unless otherwise

permitted by the department.” See also Response to Comment 3781 regarding headworks

analyses. The revised regulations at 6 NYCRR 750-3 only apply to activities within New York

State so that the additional suggested language is already implied.

Comment 6844:

Section 750-3.12(2)(ii) should be revised to state: (ii) Each discharge of produced water to these

treatment facilities shall include the following documentation: (a) The manifest stating the source

well of the high-volume hydraulic fracturing wastewater, identity of the high-volume hydraulic

fracturing permittee, and the high-volume hydraulic fracturing products used in the

hydrofracturing of the well, as well as any other information required under 6 NYCRR Part 560;

(b) The volume of high-volume hydraulic fracturing wastewater to be discharged, both per unit

time and total volume from that source; and (c) An assay of the concentrations of high-volume

hydraulic fracturing chemicals present, including total dissolved solids, naturally occurring

radioactive materials, benzene, toluene, ethylbenzene, and xylene.

Response 6844:


fracturing.

Comment 6845:

Section 750-3.12(2)(iii)(b) should be revised to state: (b) Privately owned offsite high-volume

hydraulic fracturing wastewater treatment facilities constructed specifically for the treatment and

disposal of wastewater, which treat produced water from flowback operations and the production

phase for reuse may or may not have an associated discharge of wastewater to the waters of the

State.

Response 6845:


fracturing. The revised regulations at 6 NYCRR 750-3 state “Facilities constructed specifically

for the onsite treatment of HVHF wastewater are prohibited from directly discharging to the

waters of the State pursuant to 40 CFR Part 435. These onsite facilities are not eligible to obtain

a SPDES permit. All HVHF wastewater accepted and treated by these onsite facilities must be

either reused, as approved by the department, or transported for offsite disposal at a permitted

facility.

Comment 6846:

The introduction to Section 750-3.12(3) should be revised to state: (3) The provisions below

apply to on-site and off-site treatment and recycling with no associated discharge to ground or

surface waters. On-site and off-site facilities constructed specifically for the treatment and reuse

of high-volume hydraulic fracturing wastewater where the treated water is 100 percent reused for

purposes of high-volume hydraulic fracturing do not require a State Pollutant Discharge

Elimination System permit.

Response 6846:

As per 6 NYCRR Part 750, if there is no discharge from off-site treatment and recycling, no

SPDES permit would be required. The revised regulations at 6 NYCRR 750-3 do address onsite

treatment and reuse as there are specific requirements that do apply to onsite treatment and

recycling within the oil and gas industry.

Comment 6847:

Section 750-3.12(3)(ii) should be revised to state: (ii) No residuals may remain at the high-

volume hydraulic fracturing site following completion of well development in accordance with

554.1(c)(3) of this Title. (a) No discharge of wastewater to the ground or surface waters of the

State is permitted for on-site or off-site treatment and recycling. (b) The facility shall be

maintained and construction and stormwater managed in compliance with the on-site equipment

requirements contained in the high-volume hydraulic fracturing General Permit and the

regulations listed under section 750-3.4 above.

Response 6847:

See Response to Comment 6846 regarding offsite treatment and reuse. The revised regulations

at 6 NYCRR 750-3 with respect to the disposal of wastewater from high-volume hydraulic

fracturing have been re-written. Several changes have been made for organization and/or clarity

within the regulations. See the revised regulations at 6 NYCRR 750-3 for specific changes in the

comment.

Comment 6848:

Section 750-3.12(4)(ii)(a) should be revised to state: (a) Full characterization of disposal strata

water quality for compatibility with produced water to be injected into it.

Response 6848:


fracturing. The revised regulations at 6 NYCRR 750-3 with respect to the disposal of

wastewater from high-volume hydraulic fracturing have been re-written. Several changes have

been made for organization and/or clarity within the regulations. See the revised regulations at 6

NYCRR 750-3 for specific changes in the comment for deep well injection.

Comment 6850:

The introductory text to Section 750-3.12(5) should be revised to state: (5) The provisions below

apply to injection of produced water into the strata from which it was produced pursuant to a

State Pollutant Discharge Elimination System permit. Notwithstanding the requirements listed in

6 NYCRR 556.5, the injection of produced water described in 6 NYCRR 556.5 is regulated

pursuant to this Subpart and requires a State Pollutant Discharge Elimination System permit. The

following information is required as part of the State Pollutant Discharge Elimination System

permit application:

Response 6850:

See Response to Comment 6848 regarding deep well injections.

Comment 6851:

Section 750-3.12(5)(iii) should be revised to state: iii. A water quality analysis of the produced

water from flowback operations for high-volume hydraulic fracturing chemicals.

Response 6851:

See Response to Comment 6848 regarding deep well injection.

Comment 6852:

Section 750-3.12(6) should be revised to state: (6) The provisions below apply to disposal of

produced water in accordance with the terms of a Department-approved Beneficial Use

Determination. Produced water may be disposed in accordance with the terms and conditions of

a Department-approved Beneficial Use Determination. In addition to the requirements listed in 6

NYCRR Parts 360 and 364, the following information shall also be presented as part of the

application for the Beneficial Use Determination: radiologic limits; contaminant limits; and

operational requirements such as maximum brine application frequency and maximum brine

application rate.




Comment 6853:

The title of Section 750-3.13 should be revised to: Monitoring requirements in Individual high-

volume hydraulic fracturing State Pollutant Discharge Elimination System permits.

Response 6853:

The monitoring requirements of the revised regulations at 6 NYCRR 750-3 are applicable to both

individual SPDES permits and general SPDES permits for HVHF operations. See the specific

revised regulatory requirement for the stormwater general permit for HVHF operations that

cross-references the monitoring requirements.

Comment 6854:

Section 750-3.13 (b) should be revised to: (b) For the Construction Phase, Drilling and high-

volume hydraulic fracturing Phase, and the Production Phase, all stormwater discharges must be

monitored, recorded and reported in accordance with the terms and conditions of applicable

individual or general permits to ensure effective operation.

Response 6854:

“HVHF Phase” is defined in the revised regulations at 6 NYCRR 750-3 and is the appropriate

term to include in this regulatory requirement with regard to monitoring. The revised regulations

at 6 NYCRR 750-3 do not call out the specific phases but are still applicable to all phases of

HVHF operations (“All stormwater discharges must be monitored, recorded and reported in

accordance with the terms and conditions of an applicable HVHF SPDES permit to ensure

effective operation of the stormwater controls.”)

Comment 6855:

Section 750-3.13 (c) through (i) should be deleted. The title of Section 750-3.14 should be

revised to: Schedules of compliance and other requirements in issued Individual high-volume

hydraulic fracturing State Pollutant Discharge Elimination System permits.

Response 6855:

The Department believes that all the monitoring suggested to be deleted by the commenter is

necessary for adequate oversight of HVHF operations. The monitoring requirements of the

revised regulations at 6 NYCRR 750-3 are applicable to both individual SPDES permits and

general SPDES permits for HVHF operations. See the specific revised regulatory requirement

for the stormwater general permit for HVHF operations that cross-references the monitoring

requirements.

Comment 6856:

Section 750-3.13 (b) should be revised to: (b) If stormwater discharges to a Clean Water Act

303(d) listed impaired water, when an individual high-volume hydraulic fracturing State

Pollutant Discharge Elimination System permit is obtained, the owner or operator must by

application of its Comprehensive Stormwater Pollution Prevention Plan ensure no increase in the

discharged mass loading of the listed pollutant of concern to the 303(d) listed water. The 303(d)

list is updated approximately every two years.

Response 6856:

The revised regulations at 6 NYCRR 750-3 no longer specify additional requirements for

impaired waterbodies. A SPDES permit issued for high-volume hydraulic fracturing will

address compliance with any applicable CWA section 303(d) listing.

Comment 6857:

The title of Section 750-3.15 should be revised to 750-3.15 Duration of Individual high-volume


Response 6857:

New York State law and regulation allow SPDES permits for discharges to surface waters to be

issued for up to five years. The revised regulations at 6 NYCRR 750-3 contain a separate

section on the duration of a stormwater general permit for HVHF operations. The revised

regulations at 6 NYCRR 750-3 with respect to this comment have been re-written, and have been

consolidated into other sections of the revised regulations. Several changes have been made for

organization and/or clarity within the regulations.

Comment 6858:

The title of Section 750-3.16 should be revised to: 750-3.16 Renewal of Existing Individual

high-volume hydraulic fracturing State Pollutant Discharge Elimination System permits.

Response 6858:

The revised regulations at 6 NYCRR 750-3 contain a separate section on the renewal of a

stormwater general permit for HVHF operations. The revised regulations at 6 NYCRR 750-3

with respect to this comment have been re-written, and may have been consolidated into other

sections of the revised regulations. Several changes have been made for organization and/or

clarity within the regulations.

Comment 6859:

The title of Section 750-3.17 should be revised to: 750-3.17 Transfer of Individual high-volume


Response 6859:

The revised regulations at 6 NYCRR 750-3 contain a separate section on the transfer of coverage

under a stormwater general permit for HVHF operations. The revised regulations at 6 NYCRR

750-3 with respect to this comment have been re-written, and may have been consolidated into

other sections of the revised regulations. Several changes have been made for organization

and/or clarity within the regulations.

Comment 6860:

The title of Section 750-3.18 should be revised to: 750-3.18 Modification of Individual high-

volume hydraulic fracturing State Pollutant Discharge Elimination System permits.

Response 6860:

The revised regulations at 6 NYCRR 750-3 with respect to this comment have been re-written,

and have been consolidated into other sections of the revised regulations. Several changes have

been made for organization and/or clarity within the regulations. Additionally, the revised

regulations at 6 NYCRR 750-3 state “Unless in conflict, superseded or expressly stated

otherwise in this Subpart, the provisions set forth in Subpart 750-1 and Subpart 750-2 of this Part

shall apply to HVHF operations.” This would include modifications to SPDES permits.

Comment 6861:

The title of Section 750-3.20 should be revised to 750-3.20 Denial, Suspension or Revocation of

Individual high-volume hydraulic fracturing State Pollutant Discharge Elimination System

permits.

Response 6861:

The revised regulations at 6 NYCRR 750-3 contain a separate section on the denial, suspension

or revocation of coverage under a stormwater general permit for HVHF operations. The revised

regulations at 6 NYCRR 750-3 with respect to this comment have been re-written, and have been

consolidated into other sections of the revised regulations. Several changes have been made for

organization and/or clarity within the regulations.

Comment 6862:

Section 750-3-20 should be revised to state: The regulations listed in section 750-1.20 apply to

this section. In addition to the criteria set forth in Section 621-13 and Section 750-1.20, the

Department may deny, suspend, or revoke an individual high-volume hydraulic fracturing State

Pollutant Discharge Elimination System permit if the Department determines that the permittee

has failed to implement any measures certified pursuant to Section 750-3.4, or otherwise violated

any provision of this sub-part.

Response 6862:


Comment 6863:

Section 750-3.21 (b) should be revised to state: (b) Discharges from high-volume hydraulic

fracturing operations (the Construction Phase, Drilling and high-volume hydraulic fracturing

Phase, and the Production Phase), may be authorized in accordance with a State Pollutant

Discharge Elimination System high-volume hydraulic fracturing general permit.

Response 6863:

“HVHF Phase” is part of “HVHF operations” and both are defined in the revised regulations at 6

NYCRR 750-3. The revised regulations at 6 NYCRR 750-3 with respect to this comment have

been re-written, and have been consolidated into other sections of the revised regulations.

Several changes have been made for organization and/or clarity within the regulations.

Comment 6864:

Section 750-3.21 (f) (1) should be revised to state: (f) The following are not authorized by the

high-volume hydraulic fracturing State Pollutant Discharge Elimination System general permit:

(1) Construction of a centralized impoundment for produced water from flowback or production

operations.

Response 6864:

Flowback and production brine are prohibited from being directed to or stored in any reserve pit

or freshwater impoundment. For containment of flowback and production brine, unless

otherwise approved by the department, the owner or operator must follow the requirements set

forth in revised regulations at 6 NYCRR Part 560, which indicate that covered watertight steel,

or covered watertight tanks constructed of another material approved by the Department, are

required for production brine handling and containment on the well pad. See Response to

Comment 3903. The revised regulations at 6 NYCRR Part 750-3 do not allow the construction

and use of a centralized flowback impoundment to obtain coverage under a stormwater general

permit for HVHF operations, and would require authorization under an individual SPDES permit

with a site-specific SEQRA review.

Comment 6865:

Section 750-3.21 (g) (4) should be revised to state: (4) An owner or operator shall not begin the

Drilling and high-volume hydraulic fracturing Phase until the Department is notified that the

Construction Phase is complete.

Response 6865:




Several changes have been made for organization and/or clarity within the regulations. The

revised regulations at 6 NYCRR 750-3 state generally that “[a]n owner or operator may not

commence any construction activities related to HVHF operations until its authorization to

discharge under the HVHF general permit is effective.” The specific requirements as to when

different phases of HVHF operations may occur will be contained in a stormwater general permit

for HVHF operations.

Comment 6866:

Section 750-3.21 (g) (5) should be revised to state: (5) An owner or operator shall not begin the

Production Phase until the Department is notified that the Drilling and high-volume hydraulic

fracturing Phase is complete.

Response 6866:





revised regulations at 6 NYCRR 750-3 state generally that “[a]n owner or operator may not

commence any construction activities related to HVHF operations until its authorization to

discharge under the HVHF general permit is effective.” The specific requirements as to when

different phases of HVHF operations may occur will be contained in a stormwater general permit

for HVHF operations.

Comment 6867:

Section 750-3.21 (h) should be revised to state: (h) The owner or operator shall ensure that the

provisions of the Construction Stormwater Pollution Prevention Plan are implemented from the

commencement of the Construction Phase through the Drilling and high-volume hydraulic

fracturing Phase. This includes any changes made to the Construction Stormwater Pollution

Prevention Plan.

Response 6867:





revised regulations at 6 NYCRR 750-3 state generally that “[t]he owner or operator must ensure

that the Comprehensive SWPPP is implemented. This includes any changes made to the

Comprehensive SWPPP.” The specific requirements as to when different phases of HVHF

operations may occur will be contained in a stormwater general permit for HVHF operations.

Comment 6868:

Section 750-3.21 (i) should be revised to state: (i) The owner or operator shall ensure that the

provisions of the high-volume hydraulic fracturing Stormwater Pollution Prevention Plan are

implemented from the commencement of the Drilling and high-volume hydraulic fracturing

Phase through the Production Phase, until the Notice of Termination has been submitted to the

Department. This includes any changes made to the high-volume hydraulic fracturing

Stormwater Pollution Prevention Plan.

Response 6868:





revised regulations at 6 NYCRR 750-3 state generally that “[t]he owner or operator must ensure

that the Comprehensive SWPPP is implemented. This includes any changes made to the

Comprehensive SWPPP.” The specific requirements as to when different phases of HVHF

operations may occur will be contained in a stormwater general permit for HVHF operations.

Comment 6869:

Section 750-3.21 (k) should be revised to state: (k) As set forth in subdivision 750-1.21(e) of this

Title, unless coverage has been obtained under the general permit, the Department may require

any discharger authorized to discharge in accordance with the high-volume hydraulic fracturing

general permit to apply for and obtain an individual State Pollutant Discharge Elimination

System permit or apply for authorization to discharge in accordance with another general permit.

Response 6869:

The Department retains the discretion to require an individual permit for an owner or operator

who currently holds a stormwater general permit to address, for example, non-compliance with

provision of that general permit. The revised regulations at 6 NYCRR state “As set forth in

subdivision 750-1.21(e) of this Part, the department may require any owner or operator

authorized to discharge in accordance with an HVHF general permit to apply for and obtain an

individual SPDES permit or apply for authorization to discharge in accordance with another

general permit.”

Comment 6870:

Section 750-3.21 (n) (3) should be revised to state: (3) Upon a finding of significant non-

compliance with the practice described in the high-volume hydraulic fracturing Stormwater

Pollution Prevention Plan, the Department may order an immediate stop to all activity associated

with Drilling and high-volume hydraulic fracturing Phase or the Production Phase until the non-

compliance is remedied. The stop work order shall be in writing, shall describe the non-

compliance in detail, and shall be sent to the owner or operator. A permittee must comply with

all terms of a stop work order issued pursuant to this paragraph (3).

Response 6870:





revised regulations at 6 NYCRR 750-3 state generally that “Upon a finding of significant non-

compliance with the Comprehensive SWPPP, the department may order an immediate stop to all

activity at the well until the non-compliance is remedied. The stop work order must be in

writing, describe the non-compliance in detail, and be sent to the owner or operator. “

Comment 6871:

Section 750-3.25 (d) should be revised to state: (d) For the Construction Phase, Drilling and

high-volume hydraulic fracturing Phase, and the Production Phase, all stormwater discharges

must be monitored and recorded to ensure effective operation.

Response 6871:





revised regulations at 6 NYCRR 750-3 state generally that “[a]ll stormwater discharges must be

monitored, recorded and reported in accordance with the terms and conditions of an applicable

HVHF SPDES permit to ensure effective operation of the stormwater controls.”

Comment 6873:

Section 750-3.25 (e) should be revised to state: (e) For the Construction Phase, Drilling and

high-volume hydraulic fracturing Phase, and the Production Phase, all stormwater discharges

must be reported to ensure compliance with applicable statutes, regulations and high-volume

hydraulic fracturing general permit conditions. For the Construction Phase, Drilling and high-

volume hydraulic fracturing Phase, and the Production Phase, all best management practices

must be maintained in an effective operating condition. All best management practices much be

inspected to ensure that they are in effective operating condition. Records must be kept of all

inspections. As determined by the Department, records of inspections must be reported to the

Department on a frequency adequate to prove effective operating condition of all best

management practices.

Response 6873:





revised regulations at 6 NYCRR 750-3 state generally that “[a]ll stormwater discharges must be

monitored, recorded and reported in accordance with the terms and conditions of an applicable

HVHF SPDES permit to ensure effective operation of the stormwater controls.”

Comment 6912:

Fluids Issue: Water regulations for high-volume hydraulic fracturing flowback and production

water unclear as to off-site recycling: Proposed 6 NYCRR 750-3.12 recognition that private off-

site no-discharge recycling facilities do not require State Pollutant Discharge Elimination System

permits should not be limited only for "reuse in permitted high-volume hydraulic fracturing

operations," since in the case of wastewater treated by CARES Regional Environmental

Services, LLC, the resulting product will be as pristine as rainwater and useful for any number of

applications. See 7503.12(d)(2)(iv).

Response 6912:

See Response to Comment 6846 regarding off-site recycling facilities.

Comment 6926:

750-3.2(b)(1): An access road may also be a reconstructed road used to provide access for high-

volume hydraulic fracturing activities.

Response 6926:

The department did not make any changes to the definition of “access road” as it believes the

existing definition is adequate and accurate.

Comment 6927:

750-3.2 (b)(15): Drilling fluid often includes chemicals mixed with mud, water or air.

Response 6927:

The definition of “drilling fluid” has been revised to mean “mud, water, brine, or other fluid,

including air, pumped down the drill string which acts as a lubricant and coolant for the drill bit

and is used to carry rock cuttings back up the wellbore. It may also used for pressure control in

the wellbore and to drive a mud motor and bit for directional drilling.”

Comment 6928:

750-3.2 (b)(16): Final stabilization should explicitly include language about use of native or

naturalized plants as the preferred cover.

Response 6928:

The definition of “final stabilization” has been revised to mean “all soil disturbance activities

have ceased and a uniform, perennial vegetative cover with a density of at least eighty (80)

percent has been established or other equivalent stabilization measures, such as sod, permanent

landscape mulches, rock rip-rap or washed/crushed stone, have been applied on all disturbed

areas that are not covered by permanent structures, concrete or pavement.” Further detail

regarding partial site reclamation is contained in the draft HVHF GP (e.g. seeded and mulched

after topsoil replacement and vegetative cover reestablished that will ultimately return the well

site to pre-construction conditions.”)

Comment 6930:

750-3.2(b)(18): Flowback includes chemicals and naturally occurring radioactive materials from

some formations where high-volume hydraulic fracturing is to be utilized.

Response 6930:

Comment noted. The definition of “flowback” has not changed from the draft regulations to the


Comment 6931:

750-3.2(b)(20): Freeboard applies to structures designed to hold water and both naturally-

occurring and human-added chemicals. Freeboard will not eliminate all risk of overflow, but is

intended to reduce that risk.

Response 6931:

Comment noted. The definition of “freeboard” has been revised to mean “the distance between

the maximum water surface elevation anticipated in design and the top of retaining banks or

structures. Freeboard is provided to prevent overtopping due to unforeseen conditions.”

Comment 6932:

750-3.2(b)(21): Geomembrane should have a minimum thickness and performance standards as

part of the definition.

Response 6932:

The revised regulations at 6 NYCRR 750-3 no longer contain a definition for “geomembrane.”

Comment 6933:

750-3.2(b)(22): The 1992 GEIS defined hydraulic fracturing as those operations using

approximately 80,000 gallons of water for fracturing a gas well. Section 6.10 (p. 6-289) of the

rdSGEIS (2011) discloses the differences between traditional fracturing operations and high-

volume hydraulic fracturing operations. The proposed 300,000-gallon threshold should not be

used as the operational high-volume hydraulic fracturing threshold. The threshold volume for

high-volume hydraulic fracturing should be 100,000 gallons.

Response 6933:


Comment 6934:

750-3.2(b)(23): "Any subsequent re-stimulation event" is a refracture. This should not be

permitted with the initial permit review, but should instead be dependent on satisfactory

compliance with the initial activities.

Response 6934:

The definition of “high-volume hydraulic fracturing phase” has been revised to mean “the phase

following Construction Phase Completion and through completion of Partial Site Reclamation.

This phase includes well drilling, high-volume hydraulic fracturing, and on-site handling and

treatment of HVHF wastewater produced until all wells planned for that well pad have been

completed.”

Comment 6935:

750-3.2(b)(28): High density polyethylene plastic should have a minimum thickness and

performance standards as part of the definition.

Response 6935:

The revised regulations at 6 NYCRR 750-3 no longer contain a definition for “HDPE.”

Comment 6936:

750-3.2(b)(30): Unless the Department proposes not to allow them, the definition of "hydraulic

fracturing" should include chemicals, along with proppant.

Response 6936:

See Response to Comment 6933 for the definition of “high-volume hydraulic fracturing.” Also

note the definitions in the revised regulations at 6 NYCRR 750-3 of “chemical additive” (a

substance composed of one or more chemical constituents that is intentionally added to a base

fluid) and “proppant” (a material such as sand or ceramic particles that is carried in suspension

by the fracturing fluid and that serves to keep the induced fractures open when fracturing fluid is

withdrawn after a fracture treatment.”).

Comment 6937:

750-3.2(b)(35): Partial site reclamation should explicitly include language about the use of native

or naturalized plants as the preferred cover.

Response 6937:

See Response to Comment 6928 regarding “final stabilization” and “partial site reclamation.”

Comment 6939:

750-3.2(b)(36): "Plugged and abandoned"... The definition should explicitly state that they are

done in compliance with the Department's Well Plugging Permit requirements.

Response 6939:

The revised regulations at 6 NYCRR 750-3 state “The owner or operator must plug and abandon

the gas wells pursuant to Part 555 of this Title, as adopted on XX, 20XX, prior to terminating an

HVHF SPDES permit, unless otherwise approved by the Department. Prior to plugging and

abandonment, the owner or operator must notify the department and modify the HVHF SWPPP

to include stormwater controls during plugging and abandonment operations and any reclamation

done in accordance with subdivision 560.7(l) of this Title, as adopted on XX, 20XX.”

Comment 6940:

750-3.2 (b)(43): Reclaimed or reclamation should explicitly include language about the use of

native or naturalized plants as the preferred vegetative cover.

Response 6940:

See Response to Comment 6928 regarding “final stabilization” and “partial site reclamation.”

Comment 6941:

750-3.2(b)(44): Reserve pits should be double-lined, with a passive leak detection system.

Response 6941:

The revised regulations at 6 NYCRR 750-3 states “Any reserve pit, drilling pit or mud pit on the

well pad must be maintained in a leak free condition and constructed in accordance with the

requirements set forth in paragraph 560.6(a)(4) of this Title, as adopted on XX, 20XX.

Additionally, such pits must be constructed, coated, or lined with materials that are chemically

compatible with the substance stored.”

Comment 6950:

750-3.2(b)(55): The Department should explicitly state whether re-fracturing is considered a

work over operation.

Response 6950:

A workover is not always “refracturing.” The definition of “workover” has been revised to mean

“any downhole operation in an existing well performed after initial completion that is designed

to sustain, restore or increase efficiency, make the well safer, or correct a known or potential

environmental hazard.” Re-fracturing would be used to restore or increase efficiency. See also

Response to Comment 6933 regarding the definition of “high-volume hydraulic fracturing.”

Comment 6952:

750-3.3(b): Setback distances should be explicitly stated as horizontal distance. Also, the buffer

for a primary and principle buffer distances should be extended and brought into alignment with

the buffer for public water supplies since both are irreplaceable resources for future economic

development in New York State.

Response 6952:

The revised regulations at 6 NYCRR 750-3 do state “All distances noted above are measured

from the closest edge of the HVHF well pad.” See also Responses to Comment 2453 regarding

setbacks and Comment 3785 regarding Principal Aquifers.

Comment 6953:

750-3.3(b): High-volume hydraulic fracturing should be prohibited within 500 feet of principal

aquifers. High-volume hydraulic fracturing should be prohibited within 500 feet of any water

course.

Response 6953:

See Responses to Comments 2453 and 3855 regarding setbacks, and Comment 3785 regarding

Principal Aquifers.

Comment 6954:

750-3.3(b)(2): High-volume hydraulic fracturing should be prohibited within 2000 feet of

primary aquifers. Horizontal legs of high-volume hydraulic fracturing drilling should be

prohibited from extending beneath primary aquifers. Horizontal legs of high-volume hydraulic

fracturing wells should only be allowed to be drilled under principal aquifers after undergoing

site-specific State Environmental Quality Review that incorporates at least 20 years of

groundwater monitoring in similar surrounding geology where high-volume hydraulic fracturing

operations have occurred and that confirm no transmission of high-volume hydraulic fracturing

contaminants to groundwater resources.

Response 6954:

See Responses to Comments 2453 and 3855 regarding setbacks. The revised regulations at 6

NYCRR 750-3 do state “All distances noted above are measured from the closest edge of the

HVHF well pad.” In addition to the requirement that owner or operator conduct residential

water well testing, in accordance with the requirements of revised 6 NYCRR 560.5(d), the

revised regulations at 6 NYCRR 750-3 require an approvable groundwater monitoring program

be developed and implemented. Also, the 2011 rdSGEIS discusses mitigation measures to

protect groundwater resources from contamination due to migration of fluids and gas.

Comment 6955:

750-3.4(b): All owner/operators should be required to obtain a State Pollution Discharge

Elimination System permit, there should not be a provision for coverage under a general State

Pollution Discharge Elimination System permit.

Response 6955:

ECL §70-0117, as well as 6 NYCRR 750-1.21, address the use of SPDES general permits. The

revised regulations at 6 NYCRR 750-3 also address a SPDES general permit for high-volume

hydraulic fracturing. High-volume hydraulic fracturing operations are appropriately regulated

through a general permit because they (1) involve the same or substantially similar types of

operations; (2) discharge the same types of pollutants; (3) require the same effluent limitations or

operating conditions; (4) require the same or similar monitoring; and (5) will result in minimal

adverse cumulative impacts. As high-volume hydraulic fracturing operations are generally

consistent from well site to well site, utilizing similar industrial processes and materials, the

Department has determined that a general permit adequately addresses potential sources of

contamination of water resources from high-volume hydraulic operations when a well site is

operated in accordance with general permit conditions, and in compliance with monitoring,

reporting and SWPPP requirements. Note the prohibitions in the revised regulations at 6

NYCRR 750-3, as well as the instances where HVHF operations are not eligible for coverage

under a general permit.

Comment 6956:

750-3.4(b)(1) and 750-3.12(a): Given the nature of anticipated high-volume hydraulic fracturing

operations, how can a disposal plant know their capacity relative to a high-volume hydraulic

fracturing well without knowing if/how many re-fracture events will be necessary and on what

frequency (specific times)? It would make more sense that operators must comply with this

measure for each stimulation and the Department must permit high-volume hydraulic fracturing

operations with management of the waste stream, accounting for cumulative volume as well as

efficiencies as part of their ongoing permitting process. If 750-3.12(a) remains, the waste

management certification and associated responsibility must be attached to that particular well"

with responsibility (and funding) provided by the owning interest.

Response 6956:

Each treatment facility that proposes to accept HVHF would need to include the treatment

system capacity for accepting HVHF wastewater as part of their SPDES permit application (e.g.,

POTW headworks analysis, private industrial treatment facility treatability analysis). See

Responses to Comment 3441 regarding Fluid Disposal Plans and Comment 3781 regarding

headworks analyses.

Comment 6957:

750-3.4(b)(2): Realistically, operators cannot certify that there will be no significant adverse

water quality impacts related to Marcellus and other formation cuttings. As a passive way of

addressing that reality, the Department should not allow anything but closed loop systems for

any high-volume hydraulic fracturing cuttings.

Response 6957:

See Response to Comment 4028 regarding “closed-loop systems.”

Comment 6958:

750-3.4(b)(4): There should not be provisions for using on-site pits; closed loop tank systems

should be required and all cuttings should be landfilled.

Response 6958:

See Responses to Comment 4028 regarding “closed-loop systems” and Comment 6941 regarding

leak free pits.

Comment 6959:

750-3.4(b)(4)(i): In the interest of protecting public health and natural resources over the long-

term unless the Department requires individual Chemical Abstracts Service identification (or

equivalent) for every constituent in each additive and the New York State Department of Health

certifies they pose no risk to human health and the environment, no drilling fluid or cuttings

should be stored in pits. They should be managed with closed loop systems. Suitable waste

should be disposed of in a permitted landfill.

Response 6959:


leak free pits.

Comment 6964:

750-3.4(b)(4)(ii): In this context, a "tract" of land is undefined. Impoundments should have

setbacks from neighboring property boundaries, especially in the case of non-leasing neighbors,

lest they leach or decrease property values.

Response 6964:

“Tract” is no longer used in the revised regulations at 6 NYCRR 750-3. The revised regulations

at 6 NYCRR Part 750-3 do not allow the construction and use of a centralized flowback

impoundment to obtain coverage under a stormwater general permit for HVHF operations, and

would require authorization under an individual SPDES permit with a site-specific SEQRA

review.

Comment 6965:

750-3.4(b)(4)(v): Pits should be double-lined, with a functioning passive leak detection system to

protect human and environmental health.

Response 6965:


leak free pits.

Comment 6966:

750-3.4(b)(4)(viii): It will be challenging if not impossible for operators to comply with this

provision if all chemicals used in additive products are not clearly and uniquely identified by

name and Chemical Abstracts Service number or equivalent. The department should not allow

additives for which it has not collected this information and screened it with New York State

Department of Health.

Response 6966:

The revised regulations at 6 NYCRR 750-3 requires that “[t]he owner or operator’s disclosure of

hydraulic fracturing fluid must be in accordance with subparagraph 560.3(d) of this Title, as

adopted on XX, 20XX, except that documentation must be submitted to the Department’s

satisfaction, that the proposed chemical additives exhibit reduced aquatic toxicity and pose at

least as low a potential risk to water resources and the environment as all available alternatives;

or documentation, to the Department’s satisfaction, that available alternative products are not

effective in achieving the desired results or economically feasible.”

Comment 6967:

750-3.4(b)(5): This provision implies that the only reason the Department would grant an

exception would be if fluids are to be used as part of a recycling plan. While that is

commendable, it translates to the fact that those fluids continue to present some risk on-site. As

such, this is further justification for requiring management of those fluids in closed loop systems.

Response 6967:


removal of HVHF wastewater from the well site.

Comment 6968:

750-3.4(b)(6): There should be no provisions for allowing alternative plans where fractures will

be less than 2,000 feet below ground or 1,000 feet below fresh water zone. Microfractures

resulting from high-volume hydraulic fracturing operations must be monitored to determine their

actual depth at each well. Water quality should also be monitored to determine the actual extent

(bottom depth) of the fresh water zone.

Response 6968:

See Response to Comment 4027 regarding alternative plans.

Comment 6969:

750-3.4(b)(8): The toxicity of chemical additives must be determined by the New York State

Department of Health and the Department's Division of Water.

Response 6969:


Comment 6970:

750-3.5(b): This provision must be based on documenting existing (e.g. baseline) water quality

conditions for groundwater and surface water conditions, prior to high-volume hydraulic

fracturing operations. The Department has not disclosed how a legally defensible baseline for

either resource will be established. It should implement a protocol similar to that proposed for

water well testing, or fund a citizen-based program similar to its Citizens Statewide Lake

Assessment Program monitoring program. It cannot allow high-volume hydraulic fracturing

operations to be permitted in New York State without first disclosing what will be accepted as

legally defensible baseline groundwater and surface water quality. Especially in light of the fact

that the Department has not presented any objective monitoring of mitigation effectiveness since

the implementation of the 1992 GEIS rules, it cannot be assumed that compliance with

mitigation requirements will prevent degradation of these resources.

Response 6970:

The revised regulations at 6 NYCRR 750-3 include new language regarding the Department’s

determination that groundwater or surface water quality will not be degraded. In addition to the

requirement that the owner or operator conduct residential water well testing, in accordance with

the requirements of revised 6 NYCRR 560.5(d), the revised regulations at 6 NYCRR 750-3

require an approvable groundwater monitoring program to be developed and implemented. Also,

the 2011 rdSGEIS discusses mitigation measures to protect groundwater resources from

contamination due to migration of fluids and gas.

Comment 6971:

750-3.11(d)(1&2) : Maintenance agreements with municipalities must be for the remaining life

of an improved road, and not just as long as industrial traffic uses it. The Pennsylvania Center for

Dirt and Gravel Roads makes this recommendation to municipalities because the upgraded road

(wider surface area, bigger drainage structures, etc.) requires proportionally more maintenance

funds than most rural municipalities have available.

Response 6971:

The revised regulations at 6 NYCRR 750-3 state generally that “[p]rior to terminating an HVHF

SPDES permit, the owner or operator must ensure the continued operation and maintenance of

the post-construction stormwater management practices.” This means that operation and

maintenance of that practice must be continued after termination of the SPDES permit or

coverage under a stormwater general permit for HVHF operations.

Comment 6972:

750-3.11(d)(3): It should be stipulated that the stormwater operation and maintenance plan will

be funded by the owning interest of the high-volume hydraulic fracturing gas well in perpetuity.

Corporations must not be allowed to walk away from this long-term responsibility.

Response 6972:

See Response to Comment 6971 regarding stormwater practices. The revised regulations do not

dictate the details of the operation and maintenance plans, only the goal that the practices be

operated and maintained.

Comment 6973:

750-3.11(e)(1)(i): This requirement makes no stipulation of threshold responses whereby use of

alternative additives would be required. It does not serve as an understandable regulation without

detailing precisely what criteria must be evaluated and how the Department would use this

evaluation in its permitting process. Cost is not explicitly listed as part of the feasibility

evaluation. If a measurable public health, water quality or air quality advantage can be obtained

using alternative additives, they should be required.

Response 6973:

See Response to Comment 3438. Also, the regulations do not dictate a specific product based on

the goal stated.

Comment 6975:

750-3.11(e)(1)(ii): Chemical Abstracts Service or unique equivalent identification should be

provided along with the quantity of each chemical used in the additives to protect public and

environmental health. In addition, this required inventory should be updated monthly as supplies

will vary based on well pad activity.

Response 6975:

See Response to Comment 6966 regarding disclosure. Additionally, the revised regulations at 6

NYCRR 750-3 require that “[a]t the well site, the owner or operator must maintain a list of the

chemical additives used on the well site.”

Comment 6976:

750-3.11(h): Unless the Department requires a chemical accounting of the additives used to

prepare the drilling fluids, such as Chemical Abstracts Service identification, or equivalent,

drilling fluid should be stored only in on-site, covered tanks and not in reserve pits. This would

likely increase the ground disturbance needed to accommodate needs at the well pad. Under no

circumstances should cuttings be buried on-site. Chautauqua County has a documented case of

cuttings that contaminated groundwater due to leaching.

Response 6976: See Responses to Comment 4028 regarding “closed-loop systems” and Comment 6941 regarding

leak free pits.

Comment 6978:

750-3.11(j): Flowback and production brine should be sampled and analyzed by a state-certified

laboratory to document its composition for as a way to protect public and environmental health.

Response 6978:

NYS Public Health section 502 requires all labs that analyze environmental samples to be

certified by the Environmental Laboratory Approval Program (ELAP).

Comment 6998:

750-3.12(b)(3); This provision could help to build knowledge of flowback composition on a

regional basis if sufficient sampling were required (according to standard state-certified

laboratory protocols). The Department should include required monitoring on a frequency

sufficient to fully characterize flowback over time on a per-well basis (including that generated

from re-fractures) as part of this provision.

Response 6998:

See Response to Comment 6978 regarding certified laboratories. For disposal at a treatment

facility in New York State (e.g., POTW, private industrial treatment facility), the revised

regulations at 6 NYCRR 750-3 require that each source of high-volume hydraulic fracturing

wastewater be characterized. Additionally, there must be a demonstration that the high-volume

hydraulic fracturing wastewater will not cause a violation of the facility’s effluent limits or

sludge disposal criteria, and will not result in pass through of substances present in high-volume

hydraulic fracturing wastewater, or adversely affect the facility’s treatment processes. If there is

a change in the characteristics of the high-volume hydraulic fracturing wastewater, then the

characterization must be repeated.

Comment 6999:

750-3.12(b)(4&6): The Department should clarify this provision to require the Chemical

Abstracts Service (or equivalent) for each chemical and their respective amounts in a proposed

additive. No additives should be approved in New York State that have not undergone this

disclosure and approval by New York State Department of Health prior to permitting. Drilling

companies have leases to conduct operations and develop the gas resource. That leased right

should not preclude public disclosure of chemicals used to do so especially when gas recovery

includes resources under non-leased properties. The Department should provide disclosure to the

public of any chemicals used in a particular well.

Response 6999:

See Response to Comment 6966 regarding disclosure. Additionally, the revised regulations at 6

NYCRR 750-3 require that “[a]t the well site, the owner or operator must maintain a list of the

chemical additives used on the well site.” Documents and/or information in the Department’s

possession would be available to the public, subject to the limitations of the Freedom of

Information Law.

Comment 7000:

750-3.12(d): Disposal of high-volume hydraulic fracturing flowback water or production brine at

publicly owned treatment works or other industrial treatment facilities should be prohibited

unless they are capable of treating chlorides, bromides and total dissolved solids to meet drinking

water standards.

Response 7000:

See Response to Comment 3781 regarding the headworks analysis. As per the revised

regulations at 6 NYCRR 750-3, similar requirements apply to other disposal options such as

private industrial treatment facilities and deep well injection.

Comment 7001:

750-3.12(d)(1)(vi)(c)(3) and 750-3.12(d)(2)(ii)(c): The Department does not disclose the

frequency of testing required for discharging into a publicly owned treatment works. Testing

frequency needs to be sufficient to ensure that public and environmental health are upheld during

the treatment and release/disposal of flowback and production brine. Based on experience in

Pennsylvania, bromide should be included among the constituents tested both into and out of

publicly owned treatment works.

Response 7001:

Testing parameters and frequency will be included in the SPDES permit for the facility.

Comment 7002:

750-3.12(d)(4): Use of injection wells to dispose of high-volume hydraulic fracturing wastewater

should undergo site-specific State Environmental Quality Reviews to provide for public

comment. Injection of fluids into bedrock reservoirs has been shown to cause earthquakes,

therefore injection wells must undergo the public review and comment process, which is not

incorporated into the United States Environmental Protection Agency Underground Injection

Control program.

Response 7002:

The revised regulations at 6 NYCRR 750-3 require that “HVHF wastewater may be accepted

only by a deep well injection facility that has a valid SPDES permit and is permitted by the

department to accept HVHF wastewater.” A site-specific SEQRA review would be part of the

SPDES permitting process.

Comment 7003:

750-3.12(d)(4)(d): Nested up-gradient and down-gradient groundwater monitoring wells should

be required for all disposal wells accepting high-volume hydraulic fracturing wastewater.

Response 7003:

The revised regulations at 6 NYCRR 750-3 state that the Department may require the

“installation of upgradient and downgradient monitoring wells and a monitoring program with

periodic monitoring for chemical constituents present, as well as other parameters that may be

present in the HVHF wastewater.”

Comment 7004:

750-3.12(d)(6): Production brine contains high levels of numerous contaminants including

chloride, bromide, sodium, heavy metals (lead, arsenic, barium) and volatile organic chemicals

(toluene, benzene, phenols, etc.). Road spreading of production brine is not an environmentally

sound practice and should not be considered under any circumstances for high-volume hydraulic

fracturing or traditional vertical wells. The Department approved Beneficial Use Determination

for production brine disposal must be re-evaluated and undergo State Environmental Quality

Review with an appropriate public review and comment period.

Response 7004:


Comment 7005:

750-3.12(d)(7): It is inappropriate in a generic permitting process not to disclose what other

options for production brine disposal the Department would approve. Any other or future

disposal options should undergo State Environmental Quality Review with an appropriate public

review and comment period.

Response 7005:

The revised regulations at 6 NYCRR 750-3 do not choose a disposal option and do not

encourage one suitable disposal option over another. The revised regulations at 6 NYCRR 750-3

provide the requirements for each of the options to be approved by the Department and where

appropriate requirements on the well owner or operator for disposal of HVHF wastewater. See

Response to Comment 3441, regarding the Fluid Disposal Plan.

Comment 7006:

750-3.13: Reports documenting quantities of water and their sources should be made available to

the public via a website utilizing Geospatial Information System technology georeferencing data

about water withdrawals/sources, where/how used and its disposition. This database must be

maintained in an up-to-date fashion.

Response 7006:

The revised regulations at 6 NYCRR 750-3 require that the HVHF SWPPP include “the volume

of all water delivered for use at the well site from each source. Records must be maintained

identifying each truck/pipeline delivery of water and the source of the water.” The Department

does not believe it is necessary to put such information on a website utilizing GIS. In addition to

information that may be disclosed, subject to the limitations of the Freedom of Information Law,

the draft HVHF GP requires that “The NOI, SWPPP and inspection reports required by this

general permit are public documents that the owner or operator must make available for review

and copying by any person within five (5) business of the owner or operator receiving a written

request by any such person to review the NOI, SWPPP or inspection reports. Copying of

documents will be done at the requester’s expense.”

Comment 7008:

750-3.12: Gas well owners/operators or the Department should be required to post permit

information on a public website (using Geospatial Information System technology) along with a

proposed schedule of drilling activities and trucking routes at least 30 days in advance of drilling.

Actual drilling activity dates should then be updated as drilling and high-volume hydraulic

fracturing proceeds.

Response 7008:

This comment is outside the scope of the 6 NYCRR 750-3 regulations, as it is not related to the

protection of water resources. However, documents and/or information in the Department’s

possession would be available to the public, subject to the limitations of the Freedom of

Information Law.

Comment 7009:

750-3.13(g): Any non-sanitary wastewater leaving the site should be weighed and documented at

least twice by two different state- certified scales. One scale should be as close to the point of

origin as practical and one should be at the receiving facility.

Response 7009:

The Department does not believe that the suggested edits to the regulations are required.

However, the revised regulations at 6 NYCRR 750-3 do require that the HVHF SWPPP include

documentation of “the volume of all sanitary and non-domestic wastewater produced onsite. The

HVHF SWPPP must also include a transportation record, which may also be required by Part

364 of this Title, of all sanitary and non-domestic wastewater leaving the well pad. The

transportation record must include the volume of all sanitary and non-domestic wastewater

shipped offsite by individual trucks and/or pipeline, as well as the destination of the receiving

facility(ies), and associated permit number if applicable.”

Comment 7011:

750-3.13(h): Sampling should be of any water supply, not just private water wells. All water

wells within 3,000 feet of a drill pad or within the anticipated length of the horizontal drill leg,

whichever is greatest, should be sampled and tested.

Response 7011:

See Response to Comment 3784 regarding private water well testing and groundwater

monitoring.

Comment 7012:

750-3.13(h): A list of analytes to test private water supplies for must be included in the

regulations.

Response 7012:

A list of the analytes to test private water supplies is included in the 2011 rdSGEIS and is not

appropriate for inclusion in regulations, as such is too prescriptive and would not allow for

necessary alternative or additional analytes.

Comment 7013:

750-3.13(h): Water well test results should be maintained in a database and made available to

New York State Department of Health and local health departments.

Response 7013:

The revised regulations at 6 NYCRR 750-3 state “The owner or operator must conduct

residential water well testing in accordance with the requirements of subdivision 560.5(d) of this

Title, as adopted on XX, 20XX, except that copies of test results and documentation related to

delivery of test results to owners of water wells must be sent to the New York State Department

of Health.”

Comment 7014:

750-3.13(i): In order to protect industry and the water supply owner, all aspects of water testing,

including collection, should be conducted by an Environmental Laboratory Accreditation

Program-certified laboratory, with legally defensible chain-of-custody documentation in the

event the data is needed in court. All test results should be shared with the local health

department. The Department should coordinate the creation of a database accessible by their

counterparts, and State and local health departments in both New York and Pennsylvania to

facilitate informed and timely investigation of water contamination complaints.

Response 7014:

See Responses to Comment 6978 regarding ELAP, and Comment 7013 regarding disclosure to

NYSDOH.

Comment 7015:

750-3.14(c): Total maximum daily loads are often conducted / modeled based on certain flow

conditions. Water withdrawals from total maximum daily load watersheds may change the

operating assumptions for load allocations and could realistically increase concentrations of

pollutants. The phrase total maximum daily load is mentioned only once in the rdSGEIS and no

mitigation has been developed to account for this possibility.

Response 7015:

See Response to Comment 5954 regarding TMDLs.

Comment 7016:

750-3.14(c): Owner/operators should be required to meet total maximum daily load standards as

soon as the high-volume hydraulic fracturing State Pollutant Discharge Elimination System

permit is obtained.

Response 7016:

See Response to Comment 5954 regarding TMDLs.

Comment 7017:

750-3.21(e)(8): Remove "(unless all spilled material has been removed)."

Response 7017:

That language has been removed from the revised regulations at 6 NYCRR 750-3. However,

that requirement still applies because it is included in existing regulations at 6 NYCRR 750-

1.2(a)(27). Note that the revised regulations at 6 NYCRR 750-3 state “[u]nless in conflict,

superseded or expressly stated otherwise in this Subpart, the provisions set forth in Subpart 750-

1 and Subpart 750-2 of this Part shall apply to HVHF operations.”

Comment 7019:

750-3.21(f)(2)(iii): This provision should be modified to better align with the Soil Slope Phases

E& F, as called for here. Since 'E' is used to describe slopes 9-15%, the more appropriate slope

class within the soil name to use as the criteria would be 10% (versus 25%). In terms of

stormwater management, while operationally making things more challenging for the industry, it

could better protect water resources in New York State.

Response 7019:

See Response to Comment 2451 regarding steep slopes.

Comment 7020:

750-3.21(f)(3): These depths are inadequate and should be increased to protect fresh water

aquifers.

Response 7020:

That language has been removed from the revised regulations at 6 NYCRR 750-3. However, see

Responses to Comments 4027 and 5788 regarding the depth of drilling.

Comment 7021:

750-3.21(f)(4): These setback distances should be adjusted upward for slope considerations,

especially for wetlands, storm drains, lakes, or ponds, and perennial or intermittent streams. At a

minimum, these 'setback' for stormwater discharges should be doubled when slope of the land

between the well pad and the resource of concern is 10% or greater. This would differ from

Section 3.21(f)(2)(iii) above in that this provision applies to discharges to the land area between

the gas well pad and the resource of concern whereas the former applies to discharges from

construction activities themselves on steeper slopes.

Response 7021:


provisions in the regulations-one is for prohibitions and the other is for where HVHF operations

are ineligible for coverage under a general permit.

Comment 7022:

750-3.21(f)(4): This chart should include primary aquifer buffer of 2,000 feet and buffers from

all other water courses should be increased from 150 to 500 feet.

Response 7022:


provisions in the regulations-one is for prohibitions (e.g., primary aquifers maintained at 500

feet) and the other is for where HVHF operations are ineligible for coverage under a general

permit (e.g., distance from other water courses increased to 300 feet).

Comment 7023:

750-3.21(g): When these milestones are reported to the Department they should also be updated

on a public web site.

Response 7023:

Several changes have been made for organization and/or clarity within the regulations. See the

revised regulations at 6 NYCRR 750-3 for specific changes in the comment. For example, a

Comprehensive SWPPP must be developed and a complete NOI must be submitted to the

Department even before coverage under a stormwater general permit for HVHF operations can

be obtained. Other requirements, occur after coverage is obtained and submission to the

Department is dictated by the terms of the stormwater general permit for HVHF operations.

Documents and/or information in the Department’s possession would be available to the public,

subject to the limitations of the Freedom of Information Law. Additionally, pursuant to the draft

HVHF GP “The NOI, SWPPP and inspection reports required by this general permit are public

documents that the owner or operator must make available for review and copying by any person

within five (5) business of the owner or operator receiving a written request by any such person

to review the NOI, SWPPP or inspection reports. Copying of documents will be done at the

requester’s expense.”

Comment 7024:

750-3.21(l)(2): The Department has a proposed protocol for obtaining / extending coverage

under the high-volume hydraulic fracturing permit. This provision should be amended by

removing the first sentence.

Response 7024:

The process for continuing coverage under an existing stormwater general permit for HVHF

operations is necessary for clarity about what operations are covered and what operations are not.

This process is consistent with other Department general SPDES permits.

Comment 7025:

750-3.21(n)(2&3): Remove the word "significant" from the first sentence. It is a subjective term;

removing it provides the authority and option to the Department to stop work for any instance of

non-compliance. It does not obligate them to do so but allows for the possibility.

Response 7025:

The use of “significant” is to avoid the circumstance where the Department has the authority to

stop work for any instance of non-compliance. The revised regulations at 6 NYCRR 750-3

include the procedures for the issuance of stop work orders.

Comment 7029:

Proposed Express Terms 6 NYCRR Parts 750.1 and 750.3: Section 750-3.2 - The definitions in

this section do not necessarily match the definitions for the same terms in Section 560. For

example, the definitions of high-volume hydraulic fracturing are different. In addition, there are

definitions included in this section that are not included in Section 560, and vice versa, even

though the terms are used in both sections. (32) The definition of naturally occurring radioactive

materials be modified to read: "any naturally occurring radioactive materials not subject to

regulation under the Atomic Energy Act, whose radionuclide concentrations have been enhanced

by human activities such that potential risk to human health or the environment are increased."

Consistent with the State Review of Oil and Natural Gas Regulations guidelines, these

regulations should establish risk-based numerical action levels above which naturally occurring

radioactive material is regulated taking into consideration the risk of exposure to human health

and the environment. (37) The same comments apply to the definitions for primary and principal

aquifers in this section of the proposed regulations. (46) The definition of stimulation should be

modified to read "the act of attempting to increase" a well's productivity, as not all stimulation

operations are successful. (57) The definition of a well site needs some limitation, as the phrase

"any other areas directly or indirectly impacted" is so broad as to include all gathering lines that

connect the well with larger transmission lines, for example.

Response 7029:



Comment 7032:

Section 750-3.3 (b) The setbacks listed in this subsection should be broadened in two ways. First,

under subsection (4), the distance should be extended to 3,000 feet. Second, the list of areas in

this subsection should include private water wells, as is done in Section 560.4, and not be limited

to public water supply wells.

Response 7032:


NYCRR 750-3 to the revised 6 NYCRR Parts 550-556 and 560, where appropriate. See

Response to Comment 2453 regarding setbacks.

Comment 7036:

Section 750-3.4 (b): (1) Under this subsection, "documentation" should be changed to "Certified

statement," as the term documentation could include almost any document, whether accurate or

not. Moreover, the remaining subsections under this section require certification for other items

that are required as part of the high-volume hydraulic fracturing permit application. For this

reason, certification should also be required here. (2) The allowance of on-site pits for disposal

of cuttings should simply be removed from this subsection, so that closed loop drilling is

required for all applications. (4) If pits continue to be allowed under this subsection, a

requirement should be added that written landowner consent be obtained, with specific

description as to the nature and risks of long-term on-site burial. Under subsection (viii), the

language that materials be "chemically compatible with the substance stored and the

environment" requires something that cannot be readily documented or shown. This language

should be modified to indicate whether this refers to their breakdown into nontoxic substances,

or their ability to withstand exposure to sunlight, etc., and how this is to be demonstrated by the

operator. (6) The certification that high-volume hydraulic fracturing operations will take place at

least 1,000 feet below the base of fresh groundwater requires a geologic and/or seismic

evaluation in order to have any actual meaning in this subsection. Such an evaluation must

consider whether that 1,000 foot interval is impervious to the movement of all fluids, for

example, and what the factual basis for the certification is. (7) The evaluation of chemical

alternatives in this subsection must be carried out by someone with an advanced degree in

chemistry or similar background. Otherwise, the evaluation is essentially useless, as any

technician could provide this evaluation with no consequence if they were inaccurate or lacking

in knowledge of basic chemistry. (8) The certification required by this subsection is laudable, but

needs to be made by someone with technical training and/or a degree in chemistry, hydrology or

geochemistry to have any real meaning. To show reduced aquatic toxicity, or to show that

something poses less risk to water resources and the environment requires scientific training in

those areas, and is not credible when asserted by a petroleum geologist or engineer, for example.

In addition, the language allowing documentation of less effectiveness or feasibility "to the

Department's satisfaction" should either be removed or strengthened to require a showing of

technical infeasibility as the only exception. Based upon experience in other states, if not

removed, this 'loophole' will quickly swallow the requirement, as industry will not make the

effort to provide this certification and will, as a matter of course, simply assert infeasibility.

Response 7036:

See Responses to Comment 3441 regarding Fluid Disposal Plans, Comment 4028 regarding

closed-loop systems, and Comment 6941 regarding leak free pits, Comments 4027 and 5788

regarding depth of drilling, and Comment 3438 regarding the alternatives analysis.

Comment 7039:

Section 750-3.6 (a): The following modified language is suggested for this subsection: "Prior to

submitting an high-volume hydraulic fracturing State Pollutant Discharge Elimination System

permit application, an owner or operator must first develop and submit a Comprehensive

Stormwater Pollution Prevention Plan....." This would more accurately reflect the intent that

these requirements are part of the application process.

Response 7039:

The revised regulations at 6 NYCRR 750-3 have been re-written. Several changes have been

made for organization and/or clarity within the regulations. The revised regulations at 6 NYCRR

750-3 require that a Comprehensive SWPPP be developed and submitted as part of the individual

SPDES permit application.

Comment 7042:

Section 750-3.11 (e) (1) (i) As the counterpart to Section 750-3.4 (8), the analysis of the criteria

for evaluating chemical alternatives with lower toxicity, etc., must be carried out by someone

with advanced scientific training and expertise. An operator cannot simply be allowed to

"consider" the criteria; there must be a careful discussion of each criterion, or this requirement

becomes meaningless. (i) Given the presence of significant naturally occurring radioactive

materials in numerous Marcellus gas well flowback fluids, the requirement that flowback fluids

be tested for naturally occurring radioactive materials is support. However, the regulation

provides no guidance or numeric standards for when levels of naturally occurring radioactive

materials require further action. In addition, the regulations need to require that the naturally

occurring radioactive materials testing results be reported to the Department. This section should

also require that, if significant levels of naturally occurring radioactive materials are found in

flowback fluids, then the well equipment must also be tested for naturally occurring radioactive

materials, as naturally occurring radioactive materials may deposit on pipes, tanks, valves and

other producing or processing equipment.

Response 7042:

See Responses to Comment 3438 regarding the alternatives analysis, and Comment 3904

regarding testing of flowback and production brine.

Comment 7043:

Section 750-3.12 (b) The reference to 750-3.5(a) may be in error here, as that draft section has no

narrative requirements. (1) There is support for the inclusion of a certification requirement by the

operators of a proper disposal facility that available capacity exists for the projected amount of

flowback and production brine over the projected life of a well. (4) The language in this

subsection should be modified to require identification of all chemicals and additives, with the

word "products" deleted. (5) This subsection should be broadened to require the posting to a

publicly accessible website all the chemicals used and their concentrations, regardless of whether

they have a Material Safety Data Sheet or not. The Material Safety Data Sheets have numerous

accuracy issues and only cover about half of the chemicals used during hydraulic fracturing, so

the regulations need to address those chemicals without Material Safety Data Sheets as well. (d)

(4) (i) and (ii) Injection well permits should be placed under Class or Type I wells, due to the

need for complete seismic surveys in the area of the well. Recent experiences in Ohio and

Arkansas show that the pressurized injection of waste in areas with active fault systems can

result in earthquakes. In order to avoid this risk in the Marcellus region, seismic surveys should

be required as part of the geotechnical information regarding "the ability of the disposal strata to

accept and retain the injected fluid."

Response 7043:


made for organization and/or clarity within the regulations. See response to Comment 6966

regarding chemical disclosure. See Response to Comment 5946 regarding deep injection wells

and seismicity.

Comment 7044:

750-3.1(b)(9) should read as follows: Chemical constituents means a discrete chemical with its

own specific name or identity such as a Chemical Abstracts Service number which is contained

within an additive product or which is formed as a consequences of such additive products' use

in high-volume hydraulic fracturing operations.

Response 7044:

The definition of “chemical constituents” has not changed in the revised regulations at 6 NYCRR

750-3, as chemical constituents is meant to identify what is utilized in high-volume hydraulic

fracturing and not that which is formed as a result of high-volume hydraulic fracturing.

Comment 7046:

Section 750-3.13 (e) The language in this subsection should be modified to require that the

records include all chemicals, with no exclusions for confidential business information, or

otherwise. If an operator wishes to make a trade secret claim for a specific chemical, the

regulation should require a specific exemption request be made to the Department, with

justification for the claim based upon the factors listed for such claims in the federal Emergency

Planning and Community Right to Know Act. (h) The regulation should require that the operator

sample and test all residential water wells within 3,000 feet of the well pad. Sampling should be

required no more than 60 days prior to commencement of operations, and following completion

of operations, at intervals of 60 days, 1 year and 5 years, at a minimum.

Response 7046:

Documents and/or information in the Department’s possession would be available to the public,

subject to the limitations of the Freedom of Information Law. See also Response to Comment

3784 regarding private water well testing and groundwater monitoring.

Comment 7047:

Section 750-3.20 The regulation should be changed to read that the Department shall deny,

suspend, or revoke a high-volume hydraulic fracturing State Pollutant Discharge Elimination

System permit, if the permittee fails to implement any measures certified or otherwise violates

the regulations.

Response 7047:

The revised regulations at 6 NYCRR 750-3 with respect to this comment have been re-written.

With respect to denial, suspension or revocation of a SPDES permit, the revised regulations state

“The requirements in this section are in addition to those listed in section 750-1.20 of this Part,

unless in conflict, superseded or expressly stated otherwise in this section. (b) The department

may deny, suspend, or revoke an HVHF SPDES permit if the permittee violates any provision of

this Subpart.”

Comment 7048:

Section 750-3.21 (f) (4) The regulation should be modified to prohibit high-volume hydraulic

fracturing operations within 3,000 feet of private water wells. In addition, this subsection should

be made consistent with the high-volume hydraulic fracturing operations prohibition distances

listed in Section 750-3.3(b).

Response 7048:

See Response to Comment 2453 regarding setbacks. The setback from private water wells was

incorrectly placed in the draft regulations at 6 NYCRR 750-3 specifying where HVHF

operations are ineligible for coverage under a general permit. The revised regulations at 6

NYCRR 750-3 correctly include the setback from private water wells within the prohibitions.

Comment 7053:

750-3.1(b)(32): The Department should develop a list of specific constituents for testing as

naturally occurring radioactive materials in New York State so that those treating flowback and

production water (and resulting residuals) know which naturally occurring radioactive materials

parameters to test for.

Response 7053:

See Response to Comment 3904 regarding required analysis for disposal options, including

testing for NORM.

Comment 7054:

750-3.1(b)(38): Please clarify what "Product" is intended to address above and beyond Chemical

Additive and Chemical Constituent. To the extent "Product" is less inclusive than Chemical

Additive and Chemical Constituent use of the broader term is recommended to require as much

information as possible regarding the make-up of flowback and production waters.

Response 7054:

The definitions of “product,” “chemical additive” and “chemical constituent” are in the revised

regulations at 6 NYCRR 750-3. See also Responses to Comment 3904 regarding required

analysis for disposal options, and Comment 3781 regarding headworks analyses and the

characterization required for such.

Comment 7055:

750-3.4(b)(1): It is not clear whether or not a "legally permissible disposal facility" must be in

New York State or could be elsewhere. If not limited to using treatment and/or disposal facilities

in New York State (which would be subject to the Department jurisdiction), would it be

acceptable to ship waste to another state that would allow disposal by methods not considered

legally permissible in New York State? At a minimum, if out-of-state treatment and/or disposal

is permitted, it should, at a minimum, be via means which are "legally permissible" in New York

State.

Response 7055:

The SPDES regulations apply to New York State permitted facilities. See also Response to

Comment 3441 regarding Fluid Disposal Plans.

Comment 7056:

750-3.11(i): All water should be fully and adequately characterized for treatment/disposal

purposes (including, but not limited to, naturally occurring radioactive materials) prior to leaving

the site.

Response 7056:

See Response to Comment 3441 regarding Fluid Disposal Plans. For disposal at a treatment

facility in New York State (e.g., POTW, private industrial treatment facility), the revised

regulations at 6 NYCRR 750-3 require that each source of high-volume hydraulic fracturing

wastewater be characterized. Additionally, there must be a demonstration that the high-volume

hydraulic fracturing wastewater will not cause a violation of the facility’s effluent limits or

sludge disposal criteria, and will not result in pass through of substances present in high-volume

hydraulic fracturing wastewater, or adversely affect the facility’s treatment processes. If there is

a change in the characteristics of the high-volume hydraulic fracturing wastewater, then the

characterization must be repeated.

Comment 7057:

750-3.12(b)(1) and (b)(2): The method for treatment and/or disposal should be via a Department-

approved method, whether or not such treatment or disposal occurs in New York. It facilities

providing flowback and production water treatment or disposal services have subsequent

compliance issues the permittee should be required to identify/certify as to a new facility(s) to

provide such services.

Response 7057:

The SPDES regulations apply to New York State permitted facilities. See Response to Comment

3441 regarding Fluid Disposal Plans.

Comment 7058:

750-3.12(d)(1): Publicly owned treatment works accepting flowback and production water

should demonstrate that it has an approved method for residuals disposal. This should

specifically include methods to address the potential presence of naturally occurring radioactive

materials in such residuals.

Response 7058:

The revised regulations at 6 NYCRR 750-3 state “Prior to being permitted to accept HVHF

wastewater the POTW must demonstrate that it has an approved method for transport and

disposal of residuals in compliance with Parts 360, 364, 380 and 381 and subdivision 750-2.8(e)

of this Part.”

Comment 7059:

750-3.12(d)(2): Privately owned industrial treatment facilities seeking approval to accept

flowback and production water should be held to the same level of treatment, oversight, and

regulatory compliance as approved publicly owned treatment works.

Response 7059:

The revised regulations at 6 NYCRR 750-3 include requirements for privately owned industrial

treatment facilities to accept flowback and production brine. The details of the regulatory

requirements for a headworks analysis for POTWs and the treatability analysis for privately

owned industrial treatment facilities are included in the revised regulations. For any disposal

option, discharge limitations in SPDES permits are developed based upon the more stringent of

aquatic, water source, or technology standards and are set at levels to ensure that the discharges

do not impair water quality standards, including those protective of wildlife and aquatic habitat.

Comment 7060:

750-3.12(d)(4): The Department should require permittees seeking to use out-of-state deep well

injection as a means to dispose of flowback and production water to meet the same substantive

requirements as in-state deep well injection disposal.

Response 7060:

The SPDES regulations apply to New York State permitted facilities. See Response to Comment

3441 regarding a Fluid Disposal Plan.

Comment 7061:

750-3.12(d)(6): The Department should consider using the beneficial use determination process

to allow for the reuse of treated flowback and production water in the high-volume hydraulic

fracturing process, thereby conserving water resources in New York State.

Response 7061:


Comment 7062:

Section 750-1.1 (b)(2): This section references sections 750-1.4 and 750-3.4, while it seems the

correct sections for prohibited discharges should be 750-1.3 and 750-3.3.

Response 7062:


made for organization and/or clarity within the regulations. Several changes have also been

made to eliminate redundancy with and/or for consistency with the revised draft regulations at 6

NYCRR Parts 550-556 and 560, where appropriate. See the revised regulations at 6 NYCRR

750-3 for specific changes mentioned in the comment.

Comment 7064:

750-3.11 (k): seems to preclude that high-volume hydraulic fracturing production water could be

tested and proven safe to use as a traction agent on roadways. is this the intent, to never allow

high-volume hydraulic fracturing production water to be used as roadway brine, no matter how

good the quality might be?

Response 7064: See Response to Comment 3898 regarding BUDs.

Comment 7065:

750-3.12(d)(1)(vi): Implies that a publicly owned treatment work must be able to "remove" total

dissolved solids in order to accept high-volume hydraulic fracturing production water. A publicly

owned treatment work will precipitate some less desirable ions and dilute the remaining salts, but

certainly will not "remove" total dissolved solids. What is the intent of this section, treatment or

removal?

Response 7065:

That language has been removed. The revised regulations at 6 NYCRR 750-3 state “The

headworks analysis must demonstrate that the HVHF wastewater will not cause a violation of the

POTW's effluent limits or sludge disposal criteria, and will not result in pass through of

substances present in HVHF wastewater, or adversely affect the POTW's treatment processes.”

Comment 10239:

6 NYCRR 750-3.4(b)(8): Is the absence of a comma after "efficacious" intentional?

Response 10239:

The absence of a comma in this context was not intentional. However, duplication and

consistency have been addressed, including cross-references in the revised 6 NYCRR 750-3 to

the revised 6 NYCRR Parts 550-556 and 560, where appropriate.

Comment 10240:

6 NYCRR 550.2 and 750-3.2: The Department should include a definition of "downhole

operation". It is undefined in the regulation.

Response 10240:

Including a definition of the term “downhole operation” is not appropriate for inclusion in the


Comment 10241:

6 NYCRR 750-3.210(10): Add ", the National Park Service," after " Office of Parks, Recreation,

and Historic Preservation (OPRHP)"

Response 10241:

The Department does not believe it necessary to make the suggested change as the Department

deals directly with the New York State OPRHP, and not National Park Service.

Comment 10242:

6 NYCRR 750-3.2(b)(34): This definition does not appear to fully account for the possibility that

the owners of the surface and of the mineral estates may differ

Response 10242:

The definition of “owner/operator” has been removed from the revised regulations at 6 NYCRR

750-3 as the definition of “owner or operator” is included in the existing regulations at 6

NYCRR 750-1.2.

Comment 10243:

6 NYCRR Part 750-3.4(b)(1): The precise meaning of "available capacity" should be specified.

High-volume hydraulic fracturing well drilling is only one part of the total impact. Well drilling

may necessitate the development of new access roads. These roads are often unpaved and gravel-

covered. The voluminous heavy truck traffic pushes stones and gravel into nearby streams and

wetlands. There will be extra runoff during storm events. The Department nowhere specifies

how this possibly serious contamination of nearby bodies of water will be mitigated by the

owner or operator. The Department should also analyze the environmental impacts on forests due

to their segmentation if access roads, pipes and drill pads were permitted, and base their analysis

on the best available scientific research.

Response 10243:

“Available capacity” in this context is related to the disposal of high-volume hydraulic fracturing

wastewater. See Response to Comment 3441 regarding Fluid Disposal Plans.

Comment 10244:

6 NYCRR Part 750-3.11 There should be no risks that contribute to aquatic toxicities being

above Maximum Contaminant Levels (MCLs). Merely replacing toxic chemicals by others that

are less toxic is unacceptable. One way to achieve acceptable levels (i.e., below MCL levels) is

to follow our recommendations that restrict the proximity of drilling wells to sensitive water

resources (see 750-3.3(b)).

Response 10244:

With respect to the disposal of high-volume hydraulic fracturing wastewater, discharge

limitations in SPDES permits are developed based upon the more stringent of aquatic, water

source, or technology standards and are set at levels to ensure that the discharges do not impair

water quality standards, including those protective of wildlife and aquatic habitat. See also

Responses to Comment 3438 regarding an alternatives analysis, and Comment 2453 regarding

setbacks from water resources.

Comment 10245:

6 NYCRR Part 750-3.11 (e)(1)(iii) What is the protocol for cases where Naturally Occurring

Radioactive Material (NORM) is above acceptable levels? Will the Department be able to

guarantee sufficient manpower to properly oversee these projects? Regulations without proper

oversight are meaningless.

Response 10245:

See Responses to Comment 3904 regarding NORM testing, Comment 3441 regarding Fluid

Disposal Plans, and Comment 3781 regarding headworks analyses.

Comment 10246:

6 NYCRR Part 750-3.12 The capability of a facility to "properly dispose" of its waste will

depend, to large extent, on how that waste is classified. "Hazardous" waste disposal requires

more stringent criteria than "industrial" waste disposal. Due to the high levels of radioactivity in

many New York State Marcellus shale wells, these wastes should be classified as "hazardous",

and disposed of accordingly. Other hazardous waste will be generated when well piping becomes

coated and clogged with radioactive brine. How to dispose of these pipes could become a major

problem after a period of use as short as five years. Safe disposal or safe reuse of thousands of

feet of radioactive piping should be included. It is of the utmost importance that the disposal of

these wastes be performed in such a manner as to not endanger public health and safety. Workers

at the site and nearby residents are especially at risk. The Department appears to have no detailed

plan if no contingent location has been identified in the permittee's Fluid Disposal Plan. The

Department must ensure that the permittee has the means to dispose of hazardous waste, prior to

granting a high-volume hydraulic fracturing permit.

Response 10246:

See Responses to Comment 5914 regarding hazardous waste, Comment 3441 regarding Fluid

Disposal Plans, and Comment 3904 regarding testing for NORM.

Comment 10247:

6 NYCRR Part 750-3.13 Residential wells should be tested for all the chemicals that will be used

during the high-volume hydraulic fracturing process in order to determine whether or not those

chemicals are pre-existing in the wells. These wells should be tested at annual intervals for as

long as the Department deems necessary. Wells up to a distance of 5,000 feet from the edge of

the well pad should be tested. The costs of the testing should be shared among the drilling

company, the individual well-owner, and the Department.

Response 10247:

See Response to Comment 3784 regarding private water well testing and groundwater

monitoring.

Comment 10248:

6 NYCRR Part 750-3: The provisions for disposal at privately owned industrial treatment

facilities are of particular concern. These facilities would be regulated as industrial wastewater

treatment plants, which must obtain a State Pollutant Discharge Elimination System (SPDES)

permit for direct discharges of treated wastewater but are generally more lightly regulated than

publicly-owned treatment works (POTWs) (for example, pursuant to Part 650, operators of

wastewater treatment plants are not required to meet certification requirements). The regulations

of Environmental Protection Agency and the Department are based on a model that recognizes

that Publicly-Owned Treatment Works aggregate waste from numerous sources but generally

regulates industrial permittees only as single-site waste producers. As a result, several potentially

important protections for groundwater and surface waters in Publicly-Owned Treatment Works

regulations may not be addressed for private facilities. These include: standards for how waste

fluids must be stored prior to treatment potentially, without explicit regulatory provisions private

treatment sites could become long-term storage sites for waste fluids in tank farms or even open

pits; insufficient requirements for secondary containment and spill prevention; certain locational

issues (such as location within 100-year floodplains): requiring well operators to submit a

contingency plan if a private treatment plant is the primary fluid disposal option; and an influent

radium limit for private treatment plants. Beyond this, the proposed rules appear to create a

major loophole for privately owned offsite high-volume hydraulic fracturing wastewater

treatment facilities constructed specifically for the treatment and disposal of wastewater, which

treat flowback water and production brine for reuse. Such facilities may or may not have an

associated discharge of wastewater to the waters of the State. Per proposed Section 750-

3.12(d)(2)(iv), those that do not include such discharges "do not require a State Pollutant

Discharge Elimination System (SPDES) permit, unless other ancillary discharges are generated

as part of the treatment system." This language would appear to preclude the need for any

individual State Pollutant Discharge Elimination System (SPDES) permit or for any high-volume

hydraulic fracturing State Pollutant Discharge Elimination System (SPDES) general permit.

Without any permit requirement, it is not clear what if any operational requirements will apply to

a "reuse facility," or how and by whom such requirements would be enforced. For example, the

proposed rules specify that the facility must demonstrate an approved method for residuals

disposal but with no permit and therefore no permit-issuing official, it is unclear when and to

whom this demonstration must be made. Also, without any permit proceeding, the requirements

of the Department's environmental justice policy would not apply to such facilities. The

proposed rules also fail to define or otherwise limit what is intended by "recycling" or "reuse" of

treated water from private off-site or on-site facilities. Furthermore, the proposal does not clearly

address whether a service company providing on-site recycling is bound by the same regulatory

standards as the well owner/operator. The Department should ensure that all private treatment

facilities handling high-volume hydraulic fracturing are regulated in a manner which is

consistent with mitigation measures deemed necessary for drilling sites and Publicly-Owned

Treatment Works and protect public health and the environment. In addition, consideration

should also be given to requiring such facilities to provide financial surety bonds.

Response 10248:

The revised regulations at 6 NYCRR 750-3 with respect to disposal options (e.g., POTWs,

privately owned industrial treatment facilities, and recycling) have been re-written. Several

changes have been made for organization and/or clarity within the regulations. See the revised

regulations at 6 NYCRR 750-3 for specific changes mentioned in the comment. See also

Response to Comment 7059 regarding POTWs and privately owned industrial treatment

facilities.

Comment 5928:

If during "the projected life of the well" the operator wants to change the approved "fluid

disposal plan" including possibly changing the "proper disposal facility", the regulations should

address how this request and approval process will proceed (whether it will be similar, or a

repetition of the original approval process). This process should be streamlined, since the review

by the Department of the properties of the flowback and production waters has already been

done.

Response 5928:

See response to Comment 3441 regarding a Fluid Disposal Plan.

Comment 2492:

[6 NYCRR Part 750-3.11(e)(1)(i)] The Owner or Operator should not be allowed to self regulate

such an important factor as the chemical components in the high-volume hydraulic fracturing

water supply. A board of independent experts or regulators should decide what chemicals, if any,

should be allowed.

Response 2492:


Comment 3160:

Best Management Practices (BMPs) are stated as mandatory control measures. This approach is

inconsistent with the typical usage of BMPs as recommended measures and would foreclose use

of more efficient or protective alternative measures. The proposed regulations and related

requirements should be revised to utilize BMPs in their intended form as recommended measures

to be utilized where appropriate, not as mandatory, inflexible requirements.

Response 3160:

The revised regulations at 6 NYCRR 750-3 state “The owner or operator must keep the HVHF

SWPPP current so that at all times it accurately documents the applicable BMPs for HVHF

operations.” Specific BMP requirements will be contained in the stormwater SPDES permit.

Comment 4322:

Section 750-3.11(d)(1), (3), and (4) of the Proposed Express Terms 6 NYCRR Part 750.3: If

such responsibility is accepted by a municipality, private owner, or institution, the operating

company should be required to make a payment to the entity of sufficient amount so that the

earnings from the principal will fund the maintenance of the stormwater management practice

indefinitely. Some municipalities and homeowner associations now accept stormwater practices

from developers only to find out later that they cannot afford to do the proper maintenance on the

practice. This has been an increasing problem and has been mentioned several times at regional

meetings by Department personnel.

Response 4322:

See Response to Comment 6971 regarding operation and maintenance of stormwater practices.

91: Part 52, Use of State Lands Administered by the

Division of Fish, Wildlife and Marine Resources

Comment 2871:

Because units and areas of the National Park System have nationally significant resources and

ownership rights vary, the National Park Service requests that National Park Service lands be

offered the same protections as State-owned lands in New York. The proposed revisions to 6

NYCRR 52.3 and to 190.8(ag), for example, could be additionally revised to read as follows:

Notwithstanding any other provision of this title, surface disturbance associated with the drilling

of a natural gas well subject to Part 560 of this Title on State lands or on lands under the

management or control of the United States National Park Service subject to the civil jurisdiction

of the state of New York is prohibited and no permit shall be issued authorizing such activity.

This prohibition shall apply to any pre-existing leases and any new leases for oil and gas

development on State lands and on lands under the management or control of the United States

National Park Service that are subject to the civil jurisdiction of the state of New York. This

prohibition, however, does not extend to access to subsurface resources under State or National

Park lands from adjacent private areas. This prohibition may be waived where the Department

finds that it would effectuate a taking of valid property interests in oil and gas.

Response 2871:

See response to comment 2872 in Category 92: Part 190, State Lands administered by the

Division of Lands and Forests. In addition, the draft SGEIS provides for enhanced site-specific

mitigation with respect to proposed well locations, including those on National Park Service

lands. Section 7.9 of the SGEIS would require a site-specific analysis to mitigate impacts on

visual resources or visually sensitive areas, which would be developed in accordance with the

Department’s Program Policy DEP-00-2, Assessing and Mitigating Visual Impacts. This policy

would be implemented as part of the state permitting process for specific applications to address

the visual impacts of high-volume hydraulic fracturing projects on scenic areas. Program Policy

DEP-00-2 is designed to complement the state permitting process for specific applications,

which addresses all well pads and other activities associated with high-volume hydraulic

fracturing, and includes a process for identifying and incorporating the concerns that local

jurisdictions may express for local scenic areas. This requirement would provide meaningful

site-specific mitigation measures to reduce or eliminate visual impacts on National Park Service

lands.

Comment 5759:

6 NYCRR 25.6: Bans on Drilling in State-Owned Land is not adequate. While New York State

will prohibit well pads above ground they will allow drilling under these same lands. This should

not be allowable. Well pads should be set back far enough from New York State-owned lands to

prevent drilling under these lands (one mile to several miles). The ban on drilling should also be

extended to New York state preservation land.

Response 5759:

See response to comments 5726 and 5746 in Category 92: Part 190, State Lands administered

by the Division of Lands and Forests. With respect to Forest Preserve lands, the New York

State Constitution already prohibits leasing of these lands, which not only prohibits surface

disturbance, but also prohibits the leasing or alienation of subsurface lands. Therefore, a

regulatory ban on drilling on these lands is unnecessary.

Comment 5761:

6 NYCRR 52.3: The prohibition of any surface activity related to gas drilling on any New York

State lands should remain in the regulations, and should be expanded to include seismic testing.

Response 5761:

The Department agrees that the prohibition of surface disturbances associated with high-volume

hydraulic fracturing should be codified by regulation. Parts 6 NYCRR 52 and 190 prohibit such

activity. With respect to seismic testing, guidelines for seismic testing on Department

administered state-owned land are accessible on the Department’s website at

http://www.dec.ny.gov/lands/64567.html for reference. These guidelines would minimize

adverse environmental impacts caused by seismic testing and would ensure that such testing

would be undertaken in a manner so as not to be inconsistent with the purposes for which these

State lands were acquired. See response to comment 5871.

Comment 5770:

6 NYCRR 52.3: Since the prohibition does not protect subsurface resources located under New

York State-owned lands, New York and its citizens should be compensated for removal of

subsurface resources located under these Lands. The Department should assess the impacts on

these resources.

Response 5770:

The State would be compensated for the extraction of mineral resources from under State lands,

through leasing subsurface access rights and royalty payments.

Comment 5797:

The Department should prohibit horizontal hydraulic fracturing next to or under New York State

controlled bodies of water administered by the Division of Fish, Wildlife, and Marine Services.

Drilling gas wells is a textbook way to introduce methane into such bodies of water. As written,

the proposed regulations would allow horizontal shale gas wells to be drilled under New York

State lakes, which include all of the lakes in the state except the New York City reservoirs. This

means that a horizontal shale well could be drilled under Lake Cayuga, Lake Otsego etc., so long

as the well pad is setback 2,000 feet away from the lake shore. Since horizontal shale wells can

run laterally more than 2,000 feet, this would effectively enable a gas well to go under the lake

bed; which would make it highly likely that the lake water would be gassed with methane and

polluted with runoff from the well pad.

Response 5797:

See response to Comments 5726 and 5746 in Category 92: Part 190, State Lands administered

by the Division of Lands and Forests. With respect to waterbodies, see Response to

Comments 2453, 3855 and 5687 in Category 90: Part 750, State Pollutant Discharge


Fracturing Operations.

Comment 5858:

The Departments proposed regulatory changes to 6 NYSCRR 190 and 52 are hardly adequate to

protect sensitive fish and wildlife habitats. Best Management Practices are not meaningful in that

such practices are not defined in the regulations, and gas operators will have little guidance to

prevent or minimize impacts. The Department is urged to define these Best Management

Practices in the regulation.

Response 5858:

The prohibition of surface disturbances associated with high-volume hydraulic fracturing,

codified in 6 NYCRR Parts 52 and 190, is not the only measure that will protect sensitive

habitats. The Department does not agree that the draft SGEIS fails to adequately address

potential significant adverse impacts to sensitive fish and wildlife habitats. Indeed, the

Department recognized concerns regarding potential unmitigated impacts to terrestrial habitats

and included requirements in Section 7.4 of the SGEIS to protect habitats of utmost concern in

New York, namely large blocks of forests and grasslands that support declining species. Section

7.4.1.2 includes measures designed to prevent or minimize impacts from fragmentation by

preserving existing large blocks of habitats identified in Grassland and Forest Focus Areas,

including such areas that are privately-owned. In addition, best management practices are

included in Section 7.4.1.1 to reduce impacts at individual well sites. Moreover, many of the

BMPs and mitigation measures contained in the SGEIS would be enforceable when included as

permit conditions. These mitigation measures along with the regulatory prohibition of surface

disturbance on Department administered state-owned lands, and the constitutional protections

applicable to Forest Preserve lands, will further protect and mitigate habitat impacts (See section

7.4.4).

Comment 5864:

It is preferred that hydraulic fracturing not be prohibited on New York State-owned lands and

would be a meaningful compromise. The compromise may lead to a successful outcome for

those strongly in favor of hydraulic fracturing in the Marcellus Shale resource.

Response 5864:

The type and level of activity from surface disturbance associated with high-volume hydraulic

fracturing is likely to lead to impacts that would be inconsistent with the provisions of the ECL

governing these lands. See response to Comment 3763 in Category 92: Part 190, State Lands

administered by the Division of Lands and Forests. However, because the Department has

determined that it is not necessary to prohibit subsurface access to mineral resources underneath

State lands from adjacent private lands (Parts 52 and 190 would only prohibit surface

disturbances associated with high-volume hydraulic fracturing), the State would be able to

realize revenue from the leasing of subsurface rights for the extraction of mineral deposits

situated under State lands that can be reached by subsurface wellbores. See response to

Comment 5746 in Category 92: Part 190, State Lands administered by the Division of Lands

and Forests.

Comment 5871:

The Department should amend Parts 52 and 190 of 6 NYCRR to prohibit the leasing of New

York State-owned land for surface and subsurface activities associated with high-volume

hydraulic fracturing. This prohibition would expressly prevent the Department from leasing New

York State land to allow subsurface access to state owned natural gas and other mineral rights

from locations adjacent to state owned land. High-volume hydraulic fracturing is inconsistent

with the state's policies of forest and wildlife stewardship as set forth in Article XIV section 3 of

the State Constitution. Subsurface drilling would deposit hazardous wastes (comprised of the

high-volume hydraulic fracturing chemicals) permanently on State lands. The potential exists for

these wastes to contaminate surface resources. That potential is increased by a number of factors

which include migration through existing or future fissures created by seismic activity, human or

mechanical error or abandoned wells acting as conduits to the surface.

Response 5871:

See response to Comments 5726 and 5746 in Category 92: Part 190, State Lands administered

by the Division of Lands and Forests. With respect to migration of drilling fluids, a summary

of potential seismicity impacts is included in Section 6.13.2 of the draft SGEIS. This section of

the document characterizes the risks as relatively low level and explains why there is essentially

no increased risk to the public, infrastructure or natural resources from induced seismicity related

to hydraulic fracturing. Seismic monitoring systems are already in place for New York and are

described in Section 4.5.5. There are forty seismograph locations located in NY and six

surrounding states (CT, DE, MD, NJ, PA, and VT). In NY, there are sites in Albany, NYC,

Cobleskill, Lake Ozonia, Binghamton, and two secondary schools, three colleges, and 15

universities across the states. Finally, Section 8.4 of the Final SGEIS concludes that adequate

well design prevents contact between fracturing fluids and fresh groundwater sources, and text in

Chapter 6 along with Appendix 11 on subsurface fluid mobility explains why groundwater

contamination by migration of fracturing fluid is not a reasonably foreseeable impact. Chapter 7,

the Proposed Supplementary Permit Conditions (SGEIS Appendix 10), and the proposed

regulations - Parts 750-3 and 560 - also include a number of mitigation measures that will be

used to prevent and contain surface spills.

Comment 5915:

The Departments grounds for prohibiting drilling in New York State Forests, which are based on

the likelihood that fish and game will be consuming pollutants from the process and be

physically displaced from their habitats, is unacceptable.

Response 5915:

The Department respectfully disagrees. The proposed prohibition of surface disturbances

associated with high-volume hydraulic fracturing is consistent with several provisions of the

State Constitution and the ECL related to acquiring lands for forest and wildlife conservation,

protecting watersheds, preserving unique ecological communities, and providing recreational

opportunities to New Yorkers. As discussed in Section 6.4.4 of the draft SGEIS, the anticipated

surface impacts relating to forest fragmentation, increased truck traffic, noise and light pollution

could degrade wildlife habitat and public recreation experiences of New Yorkers. For example,

the drilling and trucking activities disturb the tranquility found on these lands and can cause

significant noise impacts. Also, many State forest roads serve as recreational trails for bicyclists,

horseback riders, snowmobilers and others. The level of truck traffic associated with high

volume hydraulic fracturing could present potential safety issues, and could significantly degrade

the experience for users of these roads. See response to Comment 5934.

Comment 5924:

The Department should prohibit high-volume hydraulic fracturing gas drilling and drilling

infrastructure on all state parks, state forests and wildlife management areas. Neither New York

State, nor any agency of the state should be allowed to lease the oil and gas rights under state

parks and Department managed public lands. The Department's proposed regulations prohibiting

gas drilling activities on public lands should also be expanded to prohibit gas pipeline networks,

pipeline access roads and compressor stations. The unnecessary leasing of state-owned gas rights

will encourage the routing of pipelines over state lands and promote more intensive gas drilling

on adjoining private forests. In additional, there should be at least a 2,000 foot buffer (measured

from the end of a potential horizontal fracture) around state lands.

Response 5924:

See responses to Comments 2872 and 5726 in Category 92: Part 190, State Lands

administered by the Division of Lands and Forests. . With respect to pipelines, the

Department disagrees that an absolute prohibition is necessary to ensure that these State-owned

lands are managed in a consistent manner and purposes for which they were acquired.

Specifically, pipelines will be permitted on State-owned lands only if certain provisions of the

ECL are met, and in compliance with a tract assessment in an approved Unit Management Plan.

In this regard, any activity proposed on State-owned land must be consistent with the ECL, the

purposes for which the land was acquired, as well as the Department’s Strategic Plan for State

Forest Management. A determination to permit this activity would also be subject to its own

site-specific review. Such safeguards, along with the prohibition of other surface activities

would minimize adverse environmental impacts to the maximum extent practicable.

Comment 5934:

New York State land should be for providing recreational use for its residents and wildlife

habitat and never for commercial purposes.

Response 5934:

With respect to commercial activities other than natural gas extraction through the process of

high-volume hydraulic fracturing, the comment is beyond the scope of this rule making proposal.

However, as more fully discussed in the Regulatory Impact Statement, various funding sources,

the ECL, and the New York State Constitution govern public use and the Department’s

management of State lands under its jurisdiction. For the most part the Department has acquired

land for public recreation and wildlife habitat; however, the ECL authorizes the Department to

manage certain land classifications such as reforestation areas for commercial purposes such as

timber production and oil and gas development to the extent that such uses do not interfere with

public recreation.

Comment 5938:

We recommend that consideration be given in the proposed regulations to activities on adjoining

lands which could indirectly affect the State-owned lands. Particularly, disturbance from

lighting, noise, pollution, erosion, and construction activities should be included in the

Department's analysis of potential impacts when permits are being reviewed for adjacent lands.

Likewise, the Department should analyze the potential disturbance and degradation of non-State

land such as National Parks, National Wildlife Refuges, and Natural Areas, etc., which may also

be affected by adjacent drilling activities. Of particular concern is the potential for spills, leaks,

and runoff of fracturing fluids and chemicals when drilling is occurring upslope from protected

lands. A sufficient buffer should be put in place around these areas. We recommend the

Department analyze fluid spill and release data from other states (Pennsylvania, Wyoming, North

Dakota, Texas, etc.) which have had high-volume hydraulic fracturing of gas wells to determine

the maximum distance at which spills and releases have had an effect on aquatic habitat. Buffer

distances could be adjusted for topographic features, roads, and other factors which may affect

fluid transport.

Response 5938:

See response to Comment 2871 and comments 5726 and 5746 in Category 92: Part 190, State

Lands administered by the Division of Lands and Forests. See also Response to Comment

2453 in Category 90: Part 750, State Pollutant Discharge Elimination System (SPDES)

Permits including permits for High Volume Hydraulic Fracturing Operations.

Comment 5939:

The proposed 6 NYCRR Part 52 conflict[s] with the States clearly articulated policy objectives

to promote the ultimate recovery of the resource and prevent waste. Indeed, this policy objective

is articulated in two separate state statutes. New York Environmental Conservation Law 23-0301

declares that it is in the public interest to provide for the operation and development of oil and

gas properties in such a manner that a greater ultimate recovery of oil and gas may be had, and

that the correlative rights of all owners and the rights of all persons including landowners and the

general public may be fully protected. Likewise, New York Energy Law 3-101(5) declares that it

is part of the energy policy of New York State to foster, encourage and promote the prudent

development and wise use of all indigenous state energy resources including, but not limited to

on-shore oil and natural gas[and] natural gas from Devonian shale formations. In addition Article

23, Title 11 specifically authorizes the Department to lease state lands for natural gas

development. Given the foregoing, Independent Oil and Gas Association recommends that Part

52 be deleted as it collectively eliminates the efficient development of the States indigenous

energy resources. Alternatively, Independent Oil and Gas Association recommends that 52.3 be

amended as proposed in Exhibit A (A copy of the Proposed Express Terms 6 NYCRR Parts 52

and 190 Use of State Lands Administered by the Division of Fish, Wildlife and Marine

Resources and Use of State Lands; Proposed Express Terms 6 NYCRR Parts 550 through 556

and 560 Subchapter B: Mineral Resources; and Proposed Express Terms 6 NYCRR Parts 750.1

and 750.3 Obtaining a State Pollutant Discharge Elimination System Permit and high-volume

hydraulic fracturing with Independent Oil and Gas Association of new York's proposed changes

submitted in track changes) to only prohibit development on State lands in the Forest Preserve.

Response 5939:

Other sections of State law require the State to balance the development of mineral resources

with the protection of natural resources. The proposed regulations accomplish this balance by

allowing access to the mineral resources underneath State lands while also protecting the natural

resources found on the surface of those lands and the use of those lands by the public. See

response to Comment 5934.

Comment 5968:

Part 52.3 and Part 190, Use of State Lands: It is agreed that the added provision that surface

disturbance associated with the drilling of a natural gas well subject to Part 560 on State owned

lands is prohibited and no permit shall be issued authorizing such activity.

Response 5968:

Comment noted.

Comment 5969:

It is commendable that drilling will not be permitted on lands under the care of the Division of

Fish, Wildlife, and Marine Resources. However, fish and game do not remain within the

boundaries of those areas.

Response 5969:

The flora and fauna of the State would be protected not only by the proposed regulations, but

also by the mitigation measures in the draft SGEIS. See response to Comment 5858.

Comment 5972:

A confusing section of the regulations concerns State Lands. The amendment of Part 52: The

use of State Lands prohibits drilling on lands administered by the Division of Fish, Wildlife and

Marine Resources is clear. However, the protection of other state lands administered by the

Division of State Lands and Forest, Division of Operations and the State Parklands is much less

clear. These amendments are clearly not compliant with the intent of State Administrative

Procedures Act. Similarly, even though the rdSGEIS discusses at some length the avoidance of

drilling in state parks (Sections 1.7.14 and 2.4.12.2), the regulations do not address banning such

drilling in State Parks. The Department is the state agency responsible for protecting the

environment of New York State against the effects of drilling for gas and oil and, therefore, these

regulations should have a comprehensive statement regarding all state lands in the regulations set

out for both the drillers and the monitors. If permits will not be allowed in lands administered by

the Department and in State Parks, then that should be stated clearly in these regulations. This

should not be a parochial, departmental set of regulations.

Response 5972:

The Department has determined that the government entities having jurisdiction over other

publicly-owned lands should decide whether or not to prohibit the use of high-volume hydraulic

fracturing on those lands. The government entity with jurisdiction over their public lands has the

authority to make and enforce such a determination, and they would be most familiar with the

management needs, public purposes, and the acquisition funding relating to such public lands.

Should other government agencies adopt regulations prohibiting high-volume hydraulic

fracturing on lands under their jurisdiction, the State’s permitting process would recognize such

prohibitions. See response to Comment 2872 in Category 92: Part 190, State Lands

administered by the Division of Lands and Forests. Furthermore, OPRHP currently has a

policy that would prohibit surface activity associated with high-volume hydraulic fracturing on

New York State park lands.

Comment 6804:

Part 52.3 should be revised to state: Notwithstanding any other provision of this title, surface

disturbance associated with the drilling of a natural gas well subject to Part 560 of this Title on

State lands is prohibited within the Forest Preserve and no permit shall be issued authorizing

such activity. This prohibition shall apply to any pre-existing leases and any new leases issued

for oil and gas development on State lands in the Forest Preserve. Nothing herein shall prohibit

subsurface access to subsurface resources located under State lands from adjacent private areas

or surface disturbance on State forest and Wildlife Management areas.

Response 6804:

Such a provision is unnecessary. The New York State Constitution already prohibits leasing

Forest Preserve lands, which not only prohibits surface disturbance, but also prohibits the leasing

or alienation of subsurface lands. See response to Comment 5759.

Comment 6052:

High-Volume Hydraulic Fracturing Proposed Regulations, 6 NYCRR Parts 52 and 190: The

proposed regulations should include protection of State lands and surface waters from

contamination of off-site hydraulic fracturing operations or transportation of waste products. No

flow-back water or chemicals used in the fracturing process should be allowed to reach rivers,

creeks streams, ponds, etc. There also needs to be an established setback of hydraulic fracturing

operations from State land property. A recommended minimum setback is 2,640 feet from State

and Federal Lands (such as the Finger Lakes National Forest on the east side of Seneca Lake)

and waterways.

Response 6052:

The comment is outside the scope of 6 NYCRR Parts 52 and 190, which address surface

disturbances associated with high-volume hydraulic fracturing on Department administered

State-owned lands. However, Sections 6.1.3 and 6.1.5 of the draft SGEIS recognize the potential

impacts to surface water bodies or groundwater from an uncontained and unmitigated surface

spill, leak or release of fluids, containing chemicals or petroleum, from high-volume hydraulic

fracturing well pad operations. Specifically, accidents, construction activity, stormwater runoff

from high-volume hydraulic fracturing, or improper chemical, petroleum or wastewater

handling, could result in a degradation of drinking water supplies. See Sections 6.1.3.4 and 6.1.5

of the SGEIS. The SGEIS specifically recognizes that partial mitigation would be unacceptable

due to the potential consequences posed by such impacts, and therefore, in addition to the

mitigation measures identified to prevent spills and potential improper runoff of wastewater, also

recommends the imposition of a range of setbacks - depending on the nature of the drinking

water supply - to conservatively add an additional layer of protection to these drinking water

supplies from significant adverse impacts from potential surface spills or other releases. Section

7.1.11 of the SGEIS; see Section 7.1.5 of the SGEIS. This broad range of protective measures,

both spill prevention and setbacks, taken together, provide an enhanced level of mitigation to

prevent potential significant adverse impacts to waterbodies. See response to Comment 5871.

With respect to setbacks from State and Federal lands, see response to Comments 2871 and 5726

in Category 92: Part 190, State Lands administered by the Division of Lands and Forests.

92: Part 190, State Lands administered by the Division of Lands and Forests

Comment 2872:

Because units and areas of the National Park System have nationally significant resources and

ownership rights vary, the National Park Service (NPS) requests that NPS lands be offered the

same protections as State-owned lands in New York. The proposed revisions to 6 NYCRR 52.3

and to 190.8(ag), for example, could be additionally revised to read as follows: Notwithstanding

any other provision of this title, surface disturbance associated with the drilling of a natural gas

well subject to Part 560 of this Title on State lands or on lands under the management or control

of the U.S. National Park Service subject to the civil jurisdiction of the state of New York is

prohibited and no permit shall be issued authorizing such activity. This prohibition shall apply to

any pre-existing leases and any new leases for oil and gas development on State lands and on

lands under the management or control of the U.S. National Park Service that are subject to the

civil jurisdiction of the state of New York. This prohibition, however, does not extend to access

to subsurface resources under State or National Park lands from adjacent private areas. This

prohibition may be waived where the Department finds that it would effectuate a taking of valid

property interests in oil and gas.

Response 2872:

The Department has determined that the government entities having jurisdiction over other

publicly-owned lands should decide whether or not to prohibit the use of high-volume hydraulic

fracturing on the surface of those lands. The government entity with jurisdiction over their

public lands has the authority to make and enforce such a determination, and would be most

familiar with the management needs, public purposes, and the acquisition funding relating to

such public lands. Should other government agencies adopt regulations prohibiting high-volume

hydraulic fracturing on the surface of lands under their jurisdiction, the State’s permitting

process would recognize such prohibitions.

Comment 3763:

6 NYCRR Part 190 Use of State Lands - The proposed revision to 190.8 prohibit surface

disturbance associated with the drilling of natural gas wells where high-volume hydraulic

fracturing is planned. As the drilling of all oil and gas wells involve surface disturbance to some

extent in the construction of access roads, well pads, and other associated facilities with the

corresponding adverse impact on forest habitats and public recreational use (see pages 6-90

through 6-91 of the rdSGEIS), all natural gas wells should be covered by this restriction.

Response 3763:

The draft SGEIS details how potential adverse impacts from high-volume hydraulic fracturing

drilling activities are significantly greater than those impacts resulting from “traditional” non-

high-volume hydraulic fracturing drilling activities. For example, high-volume hydraulic

fracturing activities disturb significantly larger land areas for a greater period of time. It is also

anticipated that there would be a significant increase in truck traffic compared to “traditional”

drilling activities. Historically, the level of disturbance from “traditional” drilling technology

has been minimal, allowing State lands to be managed for the purposes for which they were

acquired, as required under Section 9-0507 of the ECL. The type and level of activity associated

with high-volume hydraulic fracturing is likely to lead to a significant increase in acreage that

would be converted to non-forest use in the form of well pads and roads, and the concomitant

nighttime lighting, noise and other impacts would collectively be inconsistent with the provisions

of the ECL governing these lands.

Comment 5726:

The Department should prohibit high-volume hydraulic fracturing and drilling infrastructure on

all state lands, including, parks, state forests and wildlife management areas. Some suggest all

State lands should be protected by a no-drill buffer (4 mile).

Response 5726:

The Department’s regulatory prohibition on surface disturbances associated with high-volume

hydraulic fracturing on reforestation lands and wildlife management areas is based in part upon

the unique legislative and legal constraints that apply to these State-owned lands. See response

to Comment 2872. Private lands buffering State-owned lands are not subject to the same legal

constraints and legislative protections afforded to these State-owned lands. Despite this, the

Department recognized concerns regarding potential unmitigated impacts to terrestrial habitats

and permit conditions may be imposed pursuant to the draft SGEIS to protect habitats of utmost

concern in New York, namely large blocks of forests and grasslands that support declining

species that may be located on buffer lands identified in this comment. Furthermore, OPRHP

currently has a policy that would prohibit surface activity associated with high-volume hydraulic

fracturing on New York State park lands and currently does not permit any drilling on its lands,

with the exception of Allegheny State Park.

Comment 5731:

The proposed regulation needs to be clarified. Proposed additions or changes to the proposed

regulations are as follows: Paragraphs (14) and (15) of subdivision 190.1(b) of 6 NYCRR are

renumbered as (15) and (16) and a new paragraph (14) added to read as follows: Subdivision

190.1(b) refers to fires. The appropriate subdivision is 190.0. (14) 'Surface disturbance' shall

mean any actions taken to alter the existing vegetation or soil of a well site or pipelines, such as

clearing, grading, filling, and excavating. A new subdivision (ag) should be added to section

190.8 of 6 NYCRR to read as follows: (ag) Notwithstanding any other provision of this title,

surface disturbance associated with the drilling of a natural gas well and pipelines subject to Part

560 of this Title on State owned lands is prohibited and no permit shall be issued authorizing

such activity. This prohibition shall apply to any pre-existing and new leases issued for oil and

gas development on State owned lands. This prohibition shall not apply to subsurface access to

subsurface resources located under State owned lands from adjacent private areas.

Response 5731:

The Department agrees that there was a typographical error in the citation to proposed section

190.1(b)(14), which has been corrected to section 190.0(b)(14) of 6 NYCRR in the revised draft

regulations. With respect to pipelines, the Department does not believe that an absolute

prohibition is necessary to ensure that these State-owned lands are managed in a consistent

manner and purposes for which they are managed and were acquired. Specifically, pipelines will

be permitted on State-owned lands only if certain provisions of the ECL are met, and in

compliance with a tract assessment in an approved Unit Management Plan. In this regard, any

activity proposed on State-owned land must be consistent with the ECL, the purposes for which

the land was acquired, as well as the Department’s Strategic Plan for State Forest Management.

A determination to permit this activity would also be subject to its own site-specific review.

Such safeguards, along with the prohibition of other surface activities would minimize adverse

environmental impacts to the maximum extent practicable.

Comment 5732:

The Department should provide scientific justification for its decision to ban hydraulic fracturing

on state lands.

Response 5732:

As stated in the Regulatory Impact Statement (RIS), “this prohibition is consistent with several

provisions of the State Constitution and the ECL related to acquiring lands for forest and wildlife

conservation, protecting watersheds, preserving unique ecological communities, and providing

recreational opportunities to New Yorkers.” As discussed in Section 6.4.4 of the draft SGEIS,

the anticipated surface impacts relating to forest fragmentation, increased truck traffic, noise and

light pollution could degrade wildlife habitat and public recreation experiences of New Yorkers.

For example, the drilling and trucking activities disturb the tranquility found on these lands and

can cause significant noise and visual impacts. Also, many State forest roads serve as

recreational trails for bicyclists, horseback riders, snowmobilers and others. The level of truck

traffic associated with high-volume hydraulic fracturing presents potential safety issues, and

would significantly degrade the experience for users of these roads. See response to Comment

5724.

Comment 5741:

The Department should extend its ban on high-volume hydraulic fracturing to the Finger Lakes

National Forest.

Response 5741:


Comment 5746:

The Department should prohibit access to subsurface resources located under State owned lands

from adjacent private areas. The drilling of horizontal laterals should not be allowed under state

forests from outside state forests.

Response 5746:

The prohibition of surface disturbances associated with high-volume hydraulic fracturing on

Department administered State-owned lands not only considered the environmental impacts, but

also the unique legislative and legal constraints that apply to these State-owned lands. Private

lands buffering State-owned lands are not subject to the same legal constraints and legislative

protections afforded to these State-owned lands. Despite this, the Department recognized

concerns regarding potential unmitigated impacts to terrestrial habitats and included

requirements in Section 7.4.1 of the draft SGEIS to protect habitats of utmost concern in New

York, namely large blocks of forests and grasslands that support declining species. Section

7.4.1.2 includes measures designed to prevent or minimize impacts from fragmentation by

preserving existing large blocks of habitats identified in Grassland and Forest Focus Areas,

including such areas that are privately-owned. In addition, best management practices are

included in Section 7.4.1.1 to reduce impacts at individual well sites. In consideration of these

measures, the Department has determined that it is not necessary to prohibit subsurface access to

mineral resources underneath State lands from adjacent private lands, nor would such access be

inconsistent with the purposes for which these State lands were acquired. Furthermore, the

shale formations subject to high volume hydraulic fracturing have limited permeability

horizontally and minimal permeability vertically which help to confine fluids to the formation

and prevent vertical migration, thus hydraulically fractured shale would not be expected to allow

the fracturing fluid to migrate from the target formation. Finally, the State will be able to realize

revenue from the leasing of subsurface rights for the extraction of mineral deposits situated under

State lands that can be reached by subsurface wellbores.

Comment 5752:

The Department's prohibition of high-volume hydraulic fracturing on State lands should be

expanded to include all public lands.

Response 5752:


Comment 5768:

State Lands have previously been leased for Oil & Gas exploration, drilling, and extraction and

this practice should be allowed going forward.

Response 5768:

The impacts of high-volume hydraulic fracturing, while similar in nature to those of traditional

oil and gas extraction methods, differs significantly in the level of those impacts. See response

to comment 3763.

Comment 5783:

Proposed regulatory changes to 6 NYCRR Parts 190 and 52 are not adequate to protect sensitive

fish and wildlife habitats. Best Management Practices must be defined by regulation to insure

gas operators will have guidance to prevent or minimize impacts.

Response 5783:


Comment 5796:

The proposed amendments to Part 190 conflict with the States clearly articulated policy

objectives to promote the ultimate recovery of the resource and prevent waste. Indeed, this policy

objective is articulated in two separate state statutes. New York Environmental Conservation

Law (ECL) 23-0301 declares that it is in the public interest to provide for the operation and

development of oil and gas properties in such a manner that a greater ultimate recovery of oil and

gas may be had, and that the correlative rights of all owners and the rights of all persons

including landowners and the general public may be fully protected. Likewise, New York

Energy Law 3-101(5) declares that it is part of the energy policy of New York State to foster,

encourage and promote the prudent development and wise use of all indigenous state energy

resources including, but not limited to on-shore oil and natural gas[and] natural gas from

Devonian shale formations. In addition Article 23, Title 11 specifically authorizes the

Department to lease state lands for natural gas development. Given the foregoing, the

Independent Oil and Gas Association of New York (IOGA) recommends that the proposed

regulatory amendments to Part 190 be deleted as they collectively eliminate the efficient

development of the State's indigenous energy resources. Alternatively, IOGA recommends that

190.8(ag) be amended as proposed in Exhibit A (A copy of the Proposed Express Terms 6

NYCRR Parts 52 and 190 Use of State Lands Administered by the Division of Fish, Wildlife and

Marine Resources and Use of State Lands; Proposed Express Terms 6 NYCRR Parts 550

through 556 and 560 Subchapter B: Mineral Resources; and Proposed Express Terms 6 NYCRR

Parts 750.1 and 750.3 Obtaining a State Pollution Discharge Elimination System (SPDES)

Permit and High-Volume Hydro Fracturing with IOGA of new York's proposed changes

submitted in track changes) to only prohibit development on State lands in the Forest Preserve.

Response 5796:

Other sections of State law require the State to balance the development of mineral resources

with the protection of natural resources. The proposed regulations accomplish this balance by

allowing access to the mineral resources underneath State lands while also protecting the natural

resources found on the surface of those lands and the use of those lands by the public. See

response to comment 5746.

Comment 6796:

Part 190 should be revised to state: A new subdivision (ag) is added to section 190.8 of 6

NYCRR to read as follows: (ag) Notwithstanding any other provision of this title, surface

disturbance associated with the drilling of a natural gas well subject to Part 560 of this Title on

State owned lands in the Forest Preserve is prohibited and no permit shall be issued authorizing

such activity. This prohibition shall apply to any pre-existing and new leases issued for oil and

gas development on State owned lands in the Forest Preserve. This prohibition shall not apply to

subsurface access to subsurface resources located under State owned lands from adjacent private

areas or surface disturbance on State forest and Wildlife Management areas.

Response 6796:

The suggested addition to the regulations is unnecessary, because lands comprising the Forest

Preserve are prohibited from being leased under Article XIV of the NYS Constitution.

Comment 6046:


proposed regulations should include a ban on land spreading or injecting any byproduct of

hydraulic fracturing on State lands. This includes the land spreading of flowback water. This has

been done in other states with detriment to the flora and fauna. These lands are intended for

watershed protection, wildlife habitat protection, and public recreation. They should not be

compromised.

Response 6046:

The prohibition of surface disturbances associated with high-volume hydraulic fracturing,

codified in 6 NYCRR Parts 52 and 190, are not the only measures that will protect sensitive

habitats. Any activity proposed on State-owned land must be consistent with the ECL, the

purposes for which the land was acquired, as well as the Department’s Strategic Plan for State

Forest Management. A determination to permit this activity would also be subject to its own

site-specific SEQRA review. Such safeguards, along with the prohibition of other surface

activities would minimize adverse environmental impacts to the maximum extent practicable.

Furthermore, as explained in Chapter 5 and presented in Appendix 12 of the draft SGEIS,

consistent with past practice, the Department began in January 2009 notifying Part 364 haulers

applying for, modifying or renewing their Part 364 permit that flowback water may not be spread

on roads and must be disposed of at facilities authorized by the Department or transported for use

or re-use at other gas or oil wells. This prohibition is applicable to state land roads as well.

Comment 6052:


proposed regulations should include protection of State lands and surface waters from

contamination of off-site hydraulic fracturing operations or transportation of waste products. No

flow-back water or chemicals used in the fracturing process should be allowed to reach rivers,

creeks streams, ponds, etc. There also needs to be an established setback of hydraulic fracturing

operations from State land property. A recommended minimum setback is 2,640 feet from State

and Federal Lands (such as the Finger Lakes National Forest on the east side of Seneca Lake)

and waterways.

Response 6052:

See Response to Comments 6046 and 2872 and 5797 in Category 91: Part 52 Use of State

Lands Administered by the Division of Fish, Wildlife and Marine Resources.

114: General Comments on the Proposed HVHF Regulations

Comment 6054:

High-Volume Hydraulic Fracturing Proposed Regulations, 6 NYCRR Parts 52 and 190:

Floodplains are protected in the SGEIS, yet wetlands are not. These are significant surface water

resources, with sensitive habitats. Wetlands (recommended size: one acre or larger) should be

protected.

Response 6054:

The SGEIS recognizes that wetlands are sensitive resources requiring enhanced protection.

Additionally, in response to this comment and others concerning wetlands and other sensitive

water resources, the Department proposes in its revised rulemaking under 6 NYCRR 750-3 to

increase the setback of well pads from wetlands from 100 to 300 feet.

Comment 6056:

High Volume Hydraulic Fracturing Proposed Regulations, 6 NYCRR Parts 52 and 190: The

prohibition of allowing hydraulic fracturing on State lands should be permanent, with no waiver,

with no "consideration period" to re-evaluate the practices of the industry.

Response 6056:

The prohibition of surface disturbance on state-owned lands within the revised regulations at 6

NYCRR Parts 52 and 190 does not contain any language with respect to waivers or

“consideration periods.”

Comment 3073:

The socioeconomic analysis and supporting documents must be revised and republished for

additional public comment. The law requires that the Department consider utilizing approaches

which are designed to avoid undue deleterious economic effects or overly burdensome impacts

of the rule upon persons, including persons residing in New York State's rural areas, directly or

indirectly affected by it or upon the economy or administration of state or local governmental

agencies.

Response 3073:

The State Administrative Procedure Act (SAPA) requires that agencies proposing rules should

assess the impact of the rules on rural areas and local governments. The Department prepared a

Regulatory Flexibility Analysis for Small Business and Local Governments with its proposed

rules, and that analysis states that the rules will not have substantial adverse effects on small

businesses and local governments. Local governments are not required to take any affirmative

action under the proposed rules. There are indirect effects on local government discussed in the

SAPA documents accompanying the proposed rules. For example, high-volume hydraulic

fracturing in the state may lead to an increase in population and increased demand for housing

and community services in communities experiencing the greatest levels of development. In

addition, heavy truck traffic will result in local costs for road maintenance. Local governments

are encouraged to enter into Road Use agreements with operators to reduce impacts on roads.

However, it is projected that high-volume hydraulic fracturing activities would result in a

substantial increase in economic activity in the affected areas and also result in a substantial

increase in tax revenues to the state and to localities. These revenues are expected to compensate

for the types of responsibilities on local governments which may result from high-volume

hydraulic fracturing development. A detailed analysis of both positive and potentially adverse

socioeconomic impacts, along with proposed mitigation measures is discussed in Sections 6.8,

6.12 and 7.8 of the SGEIS.

The SGEIS states that with proposed mitigation measures in place, any significant

socioeconomic impacts from high-volume hydraulic fracturing activities would be mitigated to

the maximum extent practicable. The Department does not agree that additional public comment

on the socioeconomic analysis is warranted.

Comment 5603:

The Department has not properly given consideration to identifying proven and more cost-

effective alternatives to protecting the environment. Article 2 of the State Administrative

Procedure Act (SAPA) establishes minimum procedures that all agencies must follow when

promulgating regulations. Pursuant to SAPA 202(8), proposed rules must be promulgated in

substantial compliance with SAPA 202 (general rulemaking procedures), 202-a (regulatory

impact statement [RIS]), 202-b (regulatory flexibility analysis for small businesses), and 202-bb

(rural area flexibility analysis). See Matter of Medical Society of State of N.Y. v. Serio, 100

N.Y.2d 854, 869 (2003). These provisions mandate that agencies consider the economic effects

of their proposed rules and choose approaches that avoid imposing undue economic hardship.

Specifically, SAPA 202-a(1) directs that, to the extent consistent with other statutes, agencies

must "consider utilizing approaches which are designed to avoid undue deleterious economic

effects or overly burdensome impacts upon persons directly or indirectly affected by [the rule]

or upon the economy..." To this end, the RIS must contain a statement "detailing the projected

costs of the rule," including: (1) the costs to the regulated community for implementation of and

compliance with the rule, and (2) the information and methodology upon which the cost analysis

is based. SAPA 202-a(3)(c)(i), (iii). If the agency cannot provide a complete statement of costs,

it must explain the reasons why and provide a statement setting forth its best estimate of costs,

together with the information and methodology upon which that best estimate is based. SAPA

202-a(3)(c)(iv). Additionally, the RIS must contain a statement of "alternative approaches"

considered by the agency and the reasons why those alternatives were not incorporated into the

rule. SAPA 202-a(3)(g). This mandate to consider alternatives is likewise part of a lead agencys

balancing obligation under the New York State Environmental Quality Review Act (SEQRA) to

choose alternatives that, "consistent with social, economic and other considerations," protect the

environment to the maximum extent practicable. Environmental Conservation Law (ECL) 8-

0109(1), (2), (8); 6 NYCRR 617.9(b)(1), (5)(i), 5(v), 617.11(d)(2). Thus, under both statutes, the

Department is obliged to consider economic impacts and choose the more cost-effective

alternative that will achieve an equal level of environmental protection. SAPA 202-b and 202-bb

likewise echo this view relative to economic impacts on, respectively, (1) small businesses (i.e.,

businesses resident in the state, independently owned and operated, employing no more than 100

individual), and (2) rural areas (i.e., counties with population less than 200,000 or towns with

population density no more than 150 persons per square mile). See SAPA 202-b(1), 202-bb(2)(a)

& (b), 102(8), 102(10), Exec. Law 481(7). Exhibit B includes several letters from IOGA

members confirming the direct impact of the regulatory proposals on small businesses in New

York. To this end, SAPA 202-b requires agencies to issue a regulatory flexibility analysis which

includes, among other things, a description of the types and estimated number of small

businesses to which the rule will apply, compliance costs for the various types of small

businesses, economic feasibility assessment for compliance, and an indication of how the rule is

designed to minimize adverse economic impacts on small businesses (including information

regarding different approaches considered). SAPA 202-b(2). Under SAPA 202-bb, agencies

must evaluate similar considerations in a rural area flexibility analysis relative to impacts on

public and private sector interests in rural areas. SAPA 202-bb(3) (stating rural area flexibility

analysis must discuss compliance costs of various types of public and private entities in rural

areas and indicate how the rule is designed to minimize adverse impact on rural areas).

Accordingly, SAPA obligates the Department to "avoid placing unreasonable financial or

administrative burdens upon regulated persons," small businesses and rural areas and mandates

specific procedures to achieve this objective. McKinneys Cons. Laws of N.Y., SAPA 202-a,

Hist. & Stat. Notes (discussing L. 1983, c. 344, 1); see generally, SAPA 202, 202-a, 202-b, 202-

bb. Failure to abide by SAPAs requirements will result in invalidation of the regulation. See

Matter of Medical Society of the State of N.Y., Inc. v. Levin, 185 Misc. 2d 536, 544-48 (Sup.

Ct., N.Y. Cty, 2000), affd, 280 A.D.2d 309 (1st Dept 2001). The Departments Proposed

Regulations fail to comply with these SAPA mandates. See NYS Register, Sept. 28, 2011 (ID

No. ENV-39-11-00020-P) (hereinafter, the Notice). In violation of SAPA 202-a, the RIS lacks

compliance cost information as to the regulated community and, in fact, acknowledges this

omission. See generally Notice (stating only that the cost of compliance will be the same as that

associated with mitigation measures and permit conditions identified in the draft SGEIS). The

RIS also lacks a meaningful alternatives analysis, limiting such solely to the no action alternative

and permit denial. Significantly, there is no discussion of more cost-effective (but equally

protective) regulation or any explanation as to why other such measures were rejected. This

deficiency is particularly significant in light of the extremely burdensome compliance costs that

will result to the regulated community from the rules as proposed. These omissions of cost and

alternatives are also apparent in the regulatory flexibility analyses for small businesses and rural

areas, thus violating SAPA 202-b and 202-bb. These analyses effectively assume, incorrectly,

that all high-volume hydraulic fracturing operators are large, well-funded entities. Thus, there is

no meaningful consideration of the economic feasibility of compliance for "small business"

operators. See Notice (stating conclusorily "[t]here should be no economic feasibility issues

created by the proposed rules"); see also Exhibit B (letters from small businesses operators who

will be directly affected by the proposed regulations). Likewise, there is no indication as to what,

if any, alternative approaches were considered to minimize economic impact on small business

operators or private sector interests in rural areas. In an effort to complete the record concerning

the significant cost impacts of the regulatory proposals, these comments identify a number of

less costly alternatives to avoid and/or minimize these impacts to small business that the

Department is mandated by law to consider. In addition, attached as Exhibit C is an assessment

of the permitting and planning costs associated with the regulatory proposals. The high standards

being sought by the Department can be achieved by adoption of more flexible and less onerous

requirements. This will reduce the cost of compliance, while simultaneously being protective of

the environment and keep New York State competitive with other states throughout the country

that are currently enjoying the economic benefits associated with shale development. Given the

foregoing, the RIS and flexibility analyses do not comply with SAPA, which renders legally

suspect any final rules that are not based upon an evaluation of cost impacts and the

consideration of more cost-effective alternatives. See Levin, 185 Misc. 2d at 544-48, affd, 280

A.D.2d 309. However, IOGA has provided the cost justification for the adoption of more cost-

effective alternatives that will be fully protective of the environment and maintain a competitive

regulatory environment.

Response 5603:

The Department respectfully disagrees that the documents required by the State Administrative

Procedure Act (SAPA) including the Regulatory Impact Statement (RIS), the Regulatory

Flexibility Analysis for Small Business, the Rural Area Flexibility Analysis, and the Job Impact

Statement are legally insufficient. Through the SGEIS process, the Department has identified the

mitigation measures necessary to prevent or reduce significant environmental impacts. While the

cost to implement these mitigation measures is an important consideration within the SEQRA

process and the cost of implementing associated regulatory controls is an important aspect of

SAPA, the primary focus of both the mitigation measures and the proposed rules is to protect the

environment.

Nevertheless, the Department revised the RIS to include projected costs of the rules. These costs

were actually provided by the commentor, IOGA. IOGA estimates that the costs of complying

with the mitigation measures in the rdSGEIS, which formed the basis for nearly all of the

proposed rules, ranges from approximately $400,000 for the first well drilled on a pad in the

least-complex case to approximately $1,700,000 for the first well drilled on a pad subject to the

Delaware River Basin Commission (DRBC)’s jurisdiction in the most complex case. Subsequent

wells drilled on these pads would be must less expensive according to IOGA, ranging from

approximately $50,000 to $440,000. IOGA provided a spreadsheet detailing the costs predicted

by IOGA for the various permits and plans required. The Department conducted its own limited

cost assessment, and found that, with respect to at least two categories of cost estimates, IOGA’s

estimates were excessive. Also note that DRBC has not finalized its regulations, and therefore,

the associated cost projections are speculative at this point.

Unfortunately, despite repeated requests by the Department to industry to provide additional cost

of compliance information, industry has refused to provide the Department with any additional

cost information.

Comment 8886:

The Department fails to adequately address the State Administrative Procedure Act (SAPA) 202-

bb. Rural Area Flexibility Analysis. That law requires that the capacity of public and private

sector interests in rural areas to respond to state agency regulations is often constrained by an

operating environment distinctly different from that found in suburban and metropolitan areas of

the state and requires that a series of factors be considered, such as: Factors such as population

sparsity, small community size, limited access to financial and technical assistance, undeveloped

services delivery systems, lack of economies of scale and extensive reliance on part-time and

volunteer services providers inhibits rural ability to effectively address increasingly complex and

stringent regulatory requirements (Emphasis added). Except for the recognition that all the

Marcellus shale drilling would be conducted in Rural Areas, there is no discussion of the

constraints that rural areas have in responding to the changes that will occur if these rules are

adopted. There are some sweeping assumptions about costs to regulated parties, Publically

Owned Treatment Works (POTWs) and mineral rights owners. However, there is absolutely no

attempt to quantify the costs or to identify professional services to the public or private sectors in

the region. There is no indication that Department compiled any data on the services and

resources that are currently available in the rural areas, or what additional services will be

required and how these services will be provided and funded.

Response 8886:

See response to comment 3073.

Comment 8887:

State Administrative Procedures Act (SAPA), in Section 202-a: Regulatory Impact Statement,

requires that, in developing a rule, an agency shall, to the extent consistent with the objectives of

applicable statutes, consider utilizing approaches which are designed to avoid undue deleterious

economic effects or overly burdensome impacts of the rule upon persons, including persons

residing in New York state's rural areas, directly or indirectly affected by it or upon the economy

or administration of state or local governmental agencies. The Department has failed to comply

with these requirements. SAPA Section 202-a. (3) requires: (b) Needs and benefits. A statement

setting forth the purpose of, necessity for, and benefits derived from the rule, a citation for and

summary, not to exceed five hundred words, of each scientific or statistical study, report or

analysis that served as the basis for the rule, an explanation of how it was used to determine the

necessity for and benefits derived from the rule, and the name of the person that produced each

study, report or analysis; The RIS however, does not provide any scientific basis to make the

determination, only unfounded assumptions. SAPA Section 202-a. (3) requires: (c) Costs. A

statement detailing the projected costs of the rule, which shall indicate: (i)The costs for the

implementation of, and continuing compliance with, the rule to regulated persons; (ii)The costs

for the implementation of, and continued administration of, the rule to the agency and to the state

and its local governments; and (iii)The information, including the source or sources of such

information, and methodology upon which the cost analysis is based; or (iv)Where an agency

finds that it cannot fully provide a statement of such costs, a statement setting forth its best

estimate, which shall indicate the information and methodology upon which such best estimate is

based and the reason or reasons why a complete cost statement cannot be provided; 10 Because

there is extensive information available from other states on the costs to state and local

government, there is plenty of data available with which to estimate costs. However, the RIS

makes absolutely no attempt to identify and quantify the costs to state government, and gives no

explanation why these costs cannot be estimated, as required by law. SAPA Section 202-a. (3)

(e) Local government mandates. The only costs to local governments identified are

investigations of well complaints, costs to publicly owned treatment works that might accept the

waste, and damage to roads. There is extensive information available to identify the increased

demands on local governments, including but not limited to housing costs and supply, increased

costs for law enforcement, schools, spill and emergency responses and social services.

Economics experts at two leading universities in the areas affected by high-volume hydraulic

fracturing (Cornell University and Penn State University) are continuing to study the economic

impact on their regions. We urge the Department review the reports from these studies that

discuss in detail the impacts on local government resources and economies.

Response 8887:

See response to comments 3073 and 5603.

Comment 9704:

The Rural Area Flexibility Analysis mentions "control at least sixty percent of the mineral rights

in the area". The definition of "the area" should be clarified. Without suitable legal precautions,

that statement can easily be abused to claim that the 60% is met when its not rationally agreed

upon.

Response 9704:

The subject text was clarified to refer to the requisite amount of mineral rights in the proposed

spacing unit.

1

6 NYCRR Parts 52, 190, 550-556, 560, and 750

Regulations for HIGH-VOLUME HYDRAULIC FRACTURING

REVISED REGULATORY IMPACT STATEMENT (RIS)

1. STATUTORY AUTHORITY

The Department is authorized to promulgate regulations to establish requirements for high-volume

hydraulic fracturing (HVHF) and associated activities in New York State pursuant to multiple statutes which

provide general and specific authority.

General:

The Environmental Conservation Law (ECL) provides statutory authority for guaranteeing beneficial

use of the environment without risk to health and safety (ECL Section 1-0101(3)(b)), promoting and

coordinating management of water, land, fish, wildlife and air resources to assure their protection,

enhancement, and balanced utilization consistent with the environmental policy of the State taking into account

the cumulative impact upon all such resources in promulgating any rule or regulation (ECL Section 3-

0301(1)(b)), providing for the protection and management of marine and coastal resources and of wetlands,

estuaries and shorelines (ECL Section 3-0301(1)(e)), encouraging industrial, commercial, residential and

community development which provides the best usage of land areas, maximizes environmental benefits and

minimizes the effects of less desirable environmental conditions (ECL Section 3-0301(1)(g)), assuring the

preservation and enhancement of natural beauty and man-made scenic qualities (ECL Section 3-0301(1)(h)),

providing for prevention and abatement of water, land and air pollution including, but not limited to, that related

to hazardous substances, particulates, gases, dust, vapors, noise, radiation, odor, nutrients and heated liquids

(ECL Section 3-0301(1)(i)), promoting control of weeds and aquatic growth, and developing methods of

prevention and eradication assuring the preservation and enhancement of natural beauty and man-made scenic

qualities (ECL Section 3-0301(1)(k)), preventing pollution through the regulation of the storage, handling and

2

transport of solids, liquids and gases which may cause or contribute to pollution (ECL Section 3-0301(1)(m)),

promoting restoration and reclamation of degraded or despoiled areas and natural resources (ECL Section 3-

0301(1)(n)), managing the real property under the jurisdiction of the Department for the purpose of preserving,

protecting and enhancing the natural resource value for which the property was acquired or dedicated (ECL

Section 3-0301(2)(v)), and adopting environmental standards and criteria and rules and regulations to

effectuate the purposes and to secure proper enforcement of the ECL (ECL Section 3-0301(2)(a and m)).

Mineral Resources:

Statutory authority for the proposed oil and gas regulations is found in the Oil, Gas and Solution Mining

Law at ECL Sections 23-0303, 23-0305, 23-0502 and 23-0503.

ECL Section 23-0303. Title 3, Section 3 of Article 23 provides the Department with the power to

administer the Oil, Gas and Solution Mining Law, except for those responsibilities entrusted to other agencies

or officers of the state.

ECL Section 23-0305. Title 3, Section 5 of Article 23 provides that the Department shall have the

power, pursuant to paragraph 23-0305(8)(c), to: “classify and reclassify pools as oil or gas pools, or wells as oil

or gas wells, including the delineation of boundaries for purposes material to the interpretation or administration

. . .” of Article 23. Paragraph 23-0305(8)(d) also specifically provides the Department with the power to:

“require the drilling, casing, operation, plugging and replugging of wells and reclamation of surrounding land in

accordance with rules and regulations of the department in such manner as to prevent or remedy the following,

including but not limited to: the escape of oil, gas, brine or water out of one stratum into another; the intrusion

of water into oil or gas strata other than during enhanced recovery operations; the pollution of fresh water

supplies by oil, gas, salt water or other contaminants; and blowouts, cavings, seepages and fires.” Further, the

Oil, Gas & Solution Mining Law authorizes the Department to hold financial security for wells regulated under

ECL Article 23 to ensure that such wells are properly plugged and abandoned. The amount of financial security

3

required to be obtained by owners and operators is provided in statute; however, subparagraph 23-0305(8)(k)(3)

provides that: “for wells greater than six thousand feet in depth, the operator may be required to provide

additional financial security consistent with criteria contained in rules and regulations to be adopted to

implement this subparagraph.”

ECL Section 23-0501. This section establishes the statewide spacing applicable to all oil and gas wells

in the state, including horizontal shale wells, and also provides the Department with the authority to issue

permits to drill, deepen, plug back and convert a well.

ECL Section 23-0503. This section establishes the conditions under which the Department shall issue a

permit to drill, deepen, plug back or convert and provides the Department with the discretion to determine

whether a proposed spacing unit meets the policy objectives of Article 23. This section further provides the

Department with the authority to issue a spacing order.

Water Resources:

ECL Section 23-0305(8)(d) provides specific authority, as noted above, with respect to natural gas pools

or fields, for the Department to require that the drilling, casing, operation, plugging and replugging of wells and

reclamation of surrounding land is conducted in accordance with regulations that prevent the pollution of fresh

water supplies by oil, gas, salt water or other contaminants.

Broad authority for the protection of the waters of the State is further provided in the ECL. ECL Section

17-0105(2) broadly defines “waters of the State,” and includes groundwaters.

ECL Section 15-0103. This section outlines that it is in the best interests of the State to regulate and

supervise activities that deplete, defile, damage, or otherwise adversely affect the waters of the State.

ECL Section 15-0105. This section outlines the policy declaration for the Department regarding the

duty to conserve and control its water resources for the benefit of all inhabitants of the state, including that

reasonable standards of purity and quality of the waters of the state be maintained consistent with public health,

4

safety and welfare and the public enjoyment thereof. Section 15-0109. This section provides jurisdiction for

the Department to exercise its powers to perform its duties in any matter affecting the water resources of the

State for public health, safety or welfare. This includes, but is not limited to, the use of potable water for

municipalities and inhabitants of the State.

ECL Section 17-0101. This section declares it to be the public policy of the State is to maintain

reasonable standards of water purity; and to "require the use of all known available and reasonable methods to

prevent and control the pollution of the waters of the State of NY." Section 17-0103. This section states that it

is the purpose of ECL Article 17 to “to safeguard the waters of the State from pollution by preventing any new

pollution..."

ECL Section 17-0303. This section states that DEC shall have the jurisdiction to prevent the pollution

of the waters of the State in accordance with water quality standards. The water quality standard for ground

water is potable/drinkable water.

ECL Section 17-0501. This section states that it shall be unlawful to discharge to any water of the State

in violation of a water quality standard.

ECL Section 17-0511. This section makes it illegal to discharge sewage, industrial waste, or other

wastes into waters of the state unless in compliance with standards.

ECL Section 17-0807. This section prohibits the discharge of radioactive waste.

ECL Section 17-1709. This section prohibits the discharge of sewage and other offensive matter into

Lake George and Skaneateles Lake. These are the only two water bodies that have this distinction in New

York. Skaneateles Lake is the water supply for Syracuse.

ECL Section 71-1929. This Section provides for a civil penalty not to exceed $37,500/day per violation,

as well as injunctive relief, for any violations of Article 17, its accompanying regulations, or any permit issued

thereunder.

5

Lands and Forests, Fish, Wildlife and Marine Resources:

Statutory authority for the proposed regulations prohibiting activities associated with HVHF, as defined

by proposed regulation Part 560, on State-owned lands, is found in the New York State Constitution, Article

XIV, in the Lands and Forest Laws at ECL Sections 9-0105, 9-0301, 9-0501 and 9-0507, in the Fish and

Wildlife laws at ECL Sections 11-2101 and 11-2103, and in the State Nature and Historical Preserve Trust

Laws at ECL Section 45-0117.

New York State Constitution Article XIV, Section 3(1). This Constitutional provision provides: “Forest

and wild life conservation are hereby declared to be policies of the state. For the purposes of carrying out such

policies the legislature may appropriate moneys for the acquisition by the state of land, outside of the

Adirondack and Catskill parks as now fixed by law, for the practice of forest or wild life conservation.”

New York State Constitution Article XIV, Section 1. This Constitutional provision requires that Forest

Preserve lands "shall be forever kept as wild forest lands" and prohibits the sale, removal or destruction of

timber situated thereon. Article XIV, Section 1 also provides that Forest Preserve lands "shall not be leased,

sold or exchanged, or be taken by any public or private corporation."

ECL Section 9-0301. This section commands the Department to ensure that “all lands within the

Adirondack and Catskill parks, except those in the town of Dannemora… shall be forever reserved and

maintained for the free use of all the people,” pursuant to conditions set forth in Article XIV of the State

Constitution.

ECL Section 9-0105. This section establishes the Department’s jurisdiction to “exercise care, custody

and control of the several preserves, parks and other state lands” that are described in the Lands and Forest

Laws. This section further authorizes the Department to make “rules and regulations prohibiting any person or

persons from entering upon any state-owned lands.” This section also provides that the Department can

“receive and accept” lands “for conservation purposes, including but not limited to water-shed protection, forest

6

management, production of timber or other forest products, silviculture, forest and outdoor recreation and

kindred purposes.” Finally, this section authorizes the Department to manage and conserve plants and

“ecological communities that are rare in New York state” on state-owned lands under the jurisdiction of the

Department.

ECL Section 9-0501. This section authorizes the state to acquire reforestation areas, “which are adapted

for reforestation and the establishment and maintenance thereon of forests for watershed protection, the

production of timber and other forests products, and for recreation and kindred purposes. . ., which shall be

forever devoted to the planting, growth and harvesting of such trees.” This section further provides the

Department with authority to adopt “rules and regulations” to manage these lands.

ECL Section 9-0507. This section provides the Department with authority to lease State Forests for oil

and gas development. The Department in issuing such leases has the authority to prescribe the terms of the

leases and that such “leasehold rights shall not interfere with the operation of such reforestation areas for the

purposes for which they were acquired and as defined in Section 3 of article XIV of the Constitution.”

ECL Section 11-2101. This section authorizes the Department to make regulations for the use of Title

21 state owned lands. Specifically, this section provides that the Department may “prohibit, limit and manage

hunting, trapping and fishing on lands, water or lands and waters on which such grounds are established,” and

may make rules with respect to these lands that it “deems calculated to promote the public interest.”

ECL Section 11-2103. This section authorizes the State to acquire or receive lands “for the purpose of

establishing and maintaining public hunting, trapping and fishing grounds.” In order to accept such lands the

Department must determine that the lands are “suitable for purposes of fish and wildlife management.”

Furthermore, the Department has the authority to improve or develop the lands, provided that the Department

deems that such improvement is for the “best” of fish and wildlife management.

ECL Section 45-0117. This section authorizes the Department to “manage and exercise custody and

7

control of” Article 45 lands -- State Nature and Historical Preserve Trust lands. See ECL Section 45-0117(1).

This section further states that lands held under this provision are to be maintained for their “highest, best and

most important use,” including, but not limited to, “maintaining plants, animals and natural communities,” and

to “provide the public with passive recreational opportunities including, where appropriate, fishing, hunting and

trapping, or commercial fishing opportunities that are compatible with protecting the ecological significance,

historic features and natural character of the area.”

2. LEGISLATIVE OBJECTIVES

General:

In keeping with Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas

and Solution Mining Regulatory Program (Well Permit Issuance for Horizontal Drilling And High-Volume

Hydraulic Fracturing to Develop the Marcellus Shale and Other Low Permeability Gas Reservoirs), the

Department is proposing these revised regulations to ensure that potential environmental impacts resulting from

HVHF are mitigated to the maximum extent practicable. This is consistent with the legislative objectives of

guaranteeing beneficial use of the environment without risk to health and safety (ECL Section 1-0101(3)(b)),

promoting and coordinating management of water, land, fish, wildlife and air resources to assure their

protection, enhancement, and balanced utilization consistent with the environmental policy of the State taking

into account the cumulative impact upon all such resources in promulgating any rule or regulation (ECL Section

3-0301(1)(b)).

Mineral Resources:

The legislative objectives of ECL Article 23, found in Section 23-0301, recognize that it is “in the public

interest to regulate the development, production and utilization of natural resources of oil and gas in this state in

such a manner as will prevent waste; to authorize and to provide for the operation and development of oil and

gas properties in such a manner that a greater ultimate recovery of oil and gas may be had, and that the

8

correlative rights of all owners and the rights of all persons including landowners and the general public may be

fully protected, and to provide in similar fashion for the underground storage of gas, the solution mining of salt

and geothermal, stratigraphic and brine disposal wells.” This Section provides a general discussion of the

existing oil and gas program and describes the legislative objectives of the draft regulations.

The Division of Mineral Resources (DMN) is responsible for regulating the development of oil and

natural gas wells in a manner consistent with the public policy goals provided by the legislature. The first of

such goals, found at Section 23-0301, is the prevention of waste. Waste is broadly defined at ECL Section 23-

0101(20)(a) as “physical waste, as that term is generally understood in the oil and gas industry. . . ” and is

further defined at ECL Section 23-0101(20)(b) as “[t]he inefficient, excessive or improper use of, or the

unnecessary dissipation of reservoir energy. . .”, and 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. . .”

As indicated in the definition of waste, wells which are improperly drilled or operated may injure an oil

or natural gas supply to the detriment of the operator, mineral rights owners and the state as a whole. In order to

prevent such injury, the legislature adopted the modern Oil, Gas and Solution Mining Law and entrusted the

Department with the responsibility to oversee drilling operations for the benefit of the all mineral rights owners,

including owners and operators, as well as the rights of the general public.

The Department’s existing rules and regulations are designed, in part, to ensure that an owner or

operator does not drill unnecessary wells or drill wells that may injure the common source of supply or the

environment. To that end, the Department’s current regulations specify: which activities require a permit (6

NYCRR Part 552); the appropriate spacing of a well from other wells in the same pool and the setbacks

applicable to the surface location of a well (6 NYCRR Part 553); appropriate drilling practices to prevent

9

pollution of the land and/or of surface or ground water (6 NYCRR Part 554); and procedures for plugging and

abandonment of a well (6 NYCRR Part 555). Existing regulations also specify the financial security required to

be in place before a permit may be issued by the Department to drill, deepen, plug back or convert a well.

The proposed revised rulemaking involves changes to the Department’s existing regulations and will

also add a new Part 560 specific to HVHF. Several of the changes included in the proposed rules are

administrative in nature and are necessary to update existing regulations to current Department and industry

practices. Included in this category of changes are the amendments to 6 NYCRR Section 550.2, which

describes how personnel are organized, and the language proposed to be added to Section 552.2, which will

clarify that the expiration of a permit to drill, deepen, plug back or convert a well does not relieve an operator

from compliance with the terms specified in a permit when the operator commences operations in the permit

term. Definitions will also be added to Part 550 for the terms hydraulic fracturing, hydraulic fracturing fluid,

true measured depth, true vertical depth, well spud, and workover. The administrative changes noted above, as

well as the addition of definitions to Part 550, further the public policy goals of ECL Article 23 by promoting

consistency in the administration of the program and by clarifying the regulatory scheme for the regulated

community and mineral rights owners.

The proposed rules will also modify Section 551.6 to remove the blanket bond available to operators

who drill multiple wells. ECL Article 23 requires operators to post financial security to cover the cost of

plugging and abandoning wells permitted by the Department and the amount of financial security that must be

in place is provided in ECL Article 23. However for wells drilled deeper than six thousand feet, ECL Article 23

directs that the financial security requirements be set in rules and regulations promulgated by the Department.

Existing regulations cap financial security for wells greater than six thousand feet at two hundred fifty thousand

dollars for individual wells and two million dollars for multiple wells. 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

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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 the statute by ensuring wells are properly

plugged and abandoned to prevent such wells from becoming a pathway for contamination.

The proposed revised rules will also modify 6 NYCRR Section 552.2 to extend the term of a permit to

drill, deepen, plug back or convert from six months to two years. 6 NYCRR Section 552.3 is proposed to be

modified to allow the Department to re-issue a permit to another operator for a location that has already been

permitted by the Department. Extending the permit term will save Department time and resources, as it is

becoming more common for well permits to expire before an operator is able to commence operations.

Department staff spends significant time and resources to review permit application materials, conduct pre-

permit site inspections, hold hearings and issue compulsory integration orders related to permits which

eventually expire. By extending the period of time in which an operator must commence drilling activities, the

Department will avoid the unnecessary expense associated with reviewing applications for a permit to drill,

deepen, plug back and convert a well at a location which has already been approved by the Department. The

Department’s proposal to extend the permit term and to modify Section 552.3 to allow the Department to re-

issue a permit to another operator will also reduce costs on the regulated community.

Several provisions in the proposed rules will also modernize the Department’s current regulations to

make them consistent with statutory changes made to ECL Article 23 in 2005 and 2008. Chapter 386 of the

Laws of 2005 made a number of significant changes to the statewide spacing scheme in place for natural gas

wells and the proposed rules will incorporate some of those changes. For example, the legislature amended

Title 5 of Article 23 to specify the size of the spacing unit based on the depth of the well and/or the target

formation, and established a new public hearing and election process to protect the correlative rights of mineral

rights owners within the boundaries of a spacing unit established by the Department-issued permit to drill. The

Department’s proposed rules will retain the Department’s ability to issue spacing orders for wells either exempt

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from the new definition of statewide spacing or in cases where the spacing unit must be modified to protect

correlative rights. Statutory statewide spacing provisions for oil and shale wells were also adopted by the

legislature in 2008, and it was this legislative change which prompted the Governor to direct Department staff

to update the Department’s 1992 GEIS to generically address proposals to drill horizontal shale wells where

HVHF is planned. The proposed rules will also promulgate the 2008 legislative changes related to shale well

development. The proposed changes to Part 553 discussed above, concerning well spacing, fall squarely in the

public policy goals of Article 23 as the spacing of wells is an important feature in a regulatory program

designed to prevent waste.

The public policy goals of Article 23 will also be advanced through the proposed changes to 6 NYCRR

Part 554, which will impose additional recordkeeping requirements on the regulated community. A requirement

will be added to subdivision (a) of Section 554.1 for operators to submit a plan detailing the planned disposal or

disposition of drill cuttings. Existing regulations require operators to provide a disposal plan for liquid wastes

but operators were not required by existing regulation to identify their plan for disposal or beneficial re-use of

drill cuttings. The revised proposed rules would also require an owner or operator to state in the fluid disposal

plan that it will maximize the reuse and/or recycling of used drilling mud, flowback water and production brine.

As advances in the industry make it possible to drill longer wells, the Department needs to ensure that drill

cuttings are being effectively managed. This change advances the Department’s mandate to protect the

environment.

Additional recordkeeping requirements are included in the proposed rules, including a provision that

will require operators to file an interim completion report for any gap in drilling operations lasting longer than

thirty days and specifics on Sundry notices. Existing regulations require operators to file a Well Drilling and

Completion Report within thirty days of completion of any well. Information provided on the Well Drilling and

Completion Report includes the depths of formations encountered during drilling, zones which were perforated

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and treated, the true measured depth, and the depths of casing and cement. The proposed rule will require

submission of the Well Drilling and Completion Report for any gap in operations longer than thirty days due to

events which cause operators to temporarily cease operations. In those circumstances it is important for

Department staff to know the status of the well to determine whether the well is being drilled in conformance

with the permit to drill issued by the Department.

Plugging and abandonment of wells is covered by a plugging permit issued by the Department, as

provided in 6 NYCRR Part 555. The proposed rulemaking includes changes to Part 555 to increase the

minimum requirements for the plugging methods specified in Section 555.5 of the regulations. Current

regulations specified, for example, that for casing left in the ground a cement plug of at least 15 feet in length

shall be placed at the bottom of such casing. In practice, the Department regularly required a longer cement

plug to be installed. Although the existing regulations provided a minimum length for cement plugs, updating

the regulations to specify that at least a one hundred foot long cement plug is to be installed would better inform

the regulated community of the specifications required to properly plug a well. The proposed rules also specify

that the plug must span the end of the casing to ensure the casing does not become a pathway for

communication with other strata or the surface. Other proposed changes to Section 555.5 would require

operators to obtain well logs prior to plugging to aid in determining the appropriate plugging procedures to

specify in the plugging permit. The proposed rules will also clarify the density of the fluid that may be utilized

between plugs set in the bore hole during plugging of the well and will clarify the reclamation requirements for

the land adjacent to the surface location of the well. All of the proposed changes to Part 555 further the policy

objectives of both ECL Article 23 and the Department’s more general environmental policy goals by ensuring

that wells are properly plugged and do not pose public safety concerns and do not contaminate other formations

or the surrounding environment.

Operating practices of wells are addressed in 6 NYCRR Part 556. Specifically, the revised proposed

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rulemaking sets forth several actions which require that the owner or operator provide notice to the department

certain actions for which an owner operator would be required to submit a request for approval to the

department on the Sundry Well Notice and Report form, and for which approval of the department must be

obtained prior to commencing operations. For example, a request from the operator for approval to flare during

a gas well completion or re-completion, including clean-up, stimulation or testing must be submitted on the

Sundry Well Notice and Report form, and approval of the department must be obtained prior to commencing

flaring. Approval must also be obtained prior to fracturing or re-fracturing after initial completion of a well, or

to modify any previously approved plans, such as the fluid disposal plan. The revised rules also provide that the

Department may, for good cause, suspend or terminate any approval to a Sundry Notice and Report form

request.

A new Part 560 is proposed in the Department’s rulemaking to address HVHF. Hydraulic fracturing is

the injection of fluids under pressure into a well in order to induce fractures in the target formation. HVHF

involves the fracturing of wells utilizing more than three hundred thousand gallons of water as the base fluid for

fracturing operations. On September 30, 2009, the Department issued a Draft Supplemental Generic

Environmental Impact Statement (2009 dSGEIS) that evaluated the environmental impacts associated with

horizontal drilling and HVHF of low-permeability reservoirs, such as the Marcellus Shale. The 2009 dSGEIS,

which supplemented the 1992 GEIS, provided a framework for the issuance of permits to drill using HVHF for

horizontal wells and detailed the application requirements and supplementary permit conditions that would be

included in a Department-issued permit for this activity. The Department has since revised the 2009 dSGEIS

and in August 2011 the Department completed a Revised dSGEIS which includes additional environmental

mitigation measures identified during the State Environmental Quality Review Act (SEQRA) process. The new

Part 560 would promulgate many of the requirements detailed in the SGEIS. Part 560 will consist of seven

sections, beginning with section 560.1 which makes Part 560 applicable to all wells where HVHF is planned

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and where the objective formation is a low-permeability reservoir, such as the Marcellus or Utica Shale.

Section 560.1 also states that Parts 550-558 will continue to apply to the extent not superseded by Part 560.

Proposed section 560.2 contains several definitions related to HVHF including chemical additives, chemical

constituent, flowback, and HVHF, as well as definitions related to new setbacks specific to HVHF surface

activities. The revised proposed Part 560.2 includes definitions for access road entrance, additive (replaces

“chemical additive”), base fluid, CAS number, chemical disclosure registry, chemical family, complete

application, objective formation, proppant, and safety data sheet.

The revised proposed section 560.3 will promulgate many of the application requirements specified in

the SGEIS including: the need for a blowout preventer use and testing plan; detailed mapping requirements; and

disclosure of chemical additives proposed to be used during hydraulic fracturing including the proposed volume

of each additive and the proposed percent by weight of water, chemical additives and proppants, as well as an

alternatives analysis. The regulations will specify that an operator or other persons, such as a chemical supplier,

may apply to the Department for trade secret protection for information submitted to the Department pursuant to

subdivision 560.3(d). While the Department will be provided chemical additive information, it is important to

provide operators or other persons with the option to apply for trade secret protection under 6 NYCRR Part 616

in order to promote innovation in the development of more environmentally friendly chemical additives. The

applicant will be required to meet the standards set forth in the Public Officers Law to establish trade secret

protections. The revised regulations require that the pre-fracturing chemical disclosure identify each chemical

constituent to be intentionally added to the base fluid and its proposed concentration, and include clarifying

language and establishment of trade secret protections. Additionally, the revised regulations at 560.3(e) set out a

process that the Department will use to evaluate HVHF drilling permit applications, including a fifteen day

public notice period. 560.3(f) also provides for collection of fees, including ones that may be charged to the

applicant for preparation of GEISs (see 6 NYCRR 617.13 and 6 NYCRR 618.1).

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The Department proposes to promulgate additional setbacks for HVHF for surface activities. The

setbacks, located in section 560.4 of the proposed rules, are necessary to limit surface disturbance to sensitive

environmental resources such as wetlands, primary aquifers, and domestic-supply springs. The setbacks do not

apply to subsurface activities, as the mitigation measures contained in the SGEIS adequately mitigate potential

environmental impacts from subsurface activities. The revised regulations include an additional 500 foot

setback from inhabited dwellings and places of assembly. Additionally, revised Part 560.4 provides that the

Department may grant variances from the some of the setbacks to inhabited private dwellings or places of

assembly, residential water wells and domestic supply springs and water wells or springs that are used as water

supply for livestock or crops, under certain circumstances. In granting a variance, the Department shall impose

reasonable and necessary conditions to minimize any adverse impact.

Section 560.5 of the proposed revised rules will promulgate the well testing, recordkeeping and

reporting requirements in the SGEIS. This section will include requirements for well operators to test

residential water wells and domestic supply springs and water wells or springs that are used as water supply for

livestock or crops within one thousand feet of a planned natural gas well or two thousand feet if no residential

wells are available for testing within one thousand feet of the planned gas well. The regulations will also

authorize the Department to require additional water well testing after the wells permitted under 6 NYCRR Part

552 are completed, to investigate whether drilling activities have impacted residential water well quality. Also,

the revised rules require additional hydraulic fracturing fluid disclosure following well completion.

Section 560.6 of the proposed rules contains detailed well construction and operational requirements for

HVHF wells and separate subdivisions are included in the rule to specify requirements for: site preparation; site

maintenance, such as the design standards for reserve pits; drilling, hydraulic fracturing and flowback, such as

the need for intermediate casing and monitoring requirements during fracturing operations; and reclamation

requirements that specify how wastes generated on the well pad should be managed and further specifying that

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reclamation of the well site should be consistent with an invasive species management plan.

Section 560.7 of the proposed regulations set forth the waste management and reclamation requirements

for HVHF wells, including handling of pit fluids, cuttings, and flowback water and production brine; testing of

flowback water and production brine for naturally occurring radioactive material (NORM) prior to removal

from the well site, and partial and final reclamation. The revised proposed regulations at Section 560.7 add

language to clarify several of these requirements.

Although the application, construction and operation requirements contained in the SGEIS were

intended to be applied across the state as uniformly as possible through DMN’s permitting program, depending

on site-specific conditions, promulgating these requirements into regulations will provide the regulated

community and the public with more certainty of the regulatory environment. The many detailed well

construction and operational requirements contained in the new Part 560 further the policy objectives of Article

23 by ensuring wells are properly constructed for the benefit of well operators, mineral rights owners and the

general public. Improperly constructed wells carry environmental costs and have the potential to damage both

the supply of natural gas and the supply of potable water. However, a rigorous and robust regulatory program,

as provided in Part 560, furthers the state’s legislative goals by protecting the environment, human health and

the common source of supply while maximizing the ultimate recovery of natural gas with measures to.

Water Resources:

The proposed revised rulemaking at Part 750-3 advances the public policy objectives sought through

ECL Section 1-0101(3)(b)) while protecting the water resources of the State of New York. ECL Articles 15 and

17 both state that it is the policy of the State to protect water resources for the safety, use and enjoyment of the

citizens of New York State. The proposed revised regulations will ensure that all HVHF is done in accordance

with these objectives.

The proposed revised rulemaking also advances the public policy objectives sought through the ongoing

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SEQRA process by including additional environmental mitigation measures identified during the associated

public review and comment process. Although mitigation measures identified during the SEQRA process

would be enforceable through ECL Article 71 when included as permit conditions to a SPDES permit, the new

Part 750-3 will promulgate many of the requirements.

This revised rulemaking updates Section 750-1.5 to conform the existing regulation to the current

federal process for issuance of Underground Injection Control permits.

Part 750-3 will consist of twelve sections. Unless in conflict, superseded or expressly stated otherwise

in this Subpart, the provisions set forth in Subpart 750-1 and Subpart 750-2 of this Part apply to HVHF

operations.

Section 750-3.2 incorporates the definitions provided in 750-1.2 and provides additional definitions

specific for HVHF operations. These definitions assist with the implementation of the other 750-3 regulations

to protect water resources.

Section 750-3.3 prohibits certain HVHF activities and discharges and does not allow the issuance of a

SPDES permit for such activities or discharges. These specifically include well pads for HVHF operations:

within 4,000 feet of an, and including the, unfiltered surface drinking water supply watersheds; within 500 feet

of, and including, a primary aquifer; within 100 year floodplains; within 2,000 feet of any public (municipal or

otherwise) drinking water supply well, reservoir, natural lake, man-made impoundment, or spring;. within 2,000

feet of any public (municipal or otherwise) drinking water supply intake in flowing water with an additional

prohibition of 1,000 feet on each side of the main flowing waterbody and any upstream tributary to that

waterbody for a distance of 1 mile from the public drinking water supply intake; and within 500 feet of a private

water well or domestic use spring, or water supply for crops or livestock, unless the department has granted a

variance. The distances are measured from the closest edge of the HVHF well pad.

These prohibitions are necessary to meet a clear legislative objective - protection of water resources.

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HVHF operations are not consistent with the unfiltered watersheds, because these areas present unique issues in

terms of resource protection. Unfiltered water supplies depend on strict land use and development controls to

ensure that water quality is protected. Eighteen Primary Aquifers have been identified by the NYSDOH, and

due to their present use as highly productive water sources by major municipalities and their shallow nature,

they are susceptible to contamination from HVHF operations. HVHF operations must not be located in 100

year floodplains due to the potential significant adverse impacts from flooding. To allow for a factor of safety

and the necessary response time of the Department, the public water supply operator, and the well pad operator,

should a spill or release from HVHF operations occur, HVHF operations must not be located within 2,000 feet

of a public drinking water supply. The same rationale applies to HVHF operations located within 2000 feet of a

public drinking water supply intake in flowing water, and the extended prohibition for tributaries and for HVHF

operations within 500 feet of private water wells or domestic use springs, or water supply for crops or livestock.

For the purposes of obtaining a SPDES permit for HVHF operations, Section 750-3.4 states that HVHF

operations cannot commence without a valid HVHF SPDES permit.

Section 750-3.5 provides the minimum information required for the Department to determination that

groundwater or surface water quality will not be degraded.

The requirements in Sections 750-3.6, 750-3.7, and 750-3.8 protect water resources by ensuring

necessary and adequate stormwater management practices are in place and properly operated and maintained.

The requirements of these sections also ensure water resources are protected through the application of the

Uniform Procedure Act and SEQRA.

Section 750-3.6 details the requirements for an individual HVHF SPDES permit application. This

section provides a list of the certifications required including: disclosure of chemical additives; evaluation and

use of less toxic alternatives; on-site maintenance of a list of chemical additives used; residential water well

testing; removal of HVHF wastewater from the well site; secondary containment; containment of flowback and

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production brine; construction and use of reserve pits; and closed-loop system requirements; These

certifications are also regulatory requirements found in Section 750-3.7. Section 750-3.6 also requires the

proper handling and disposal of HVHF wastewater; identification of the depth of the HVHF drilling; and the

development of a comprehensive stormwater pollution prevention plan (SWPPP), which addresses the

construction, HVHF and production phases of natural gas well development through the Construction SWPPP

and HVHF SWPPP.

Section 750-3.7 details the requirements of a Comprehensive SWPPP (both the Construction SWPPP

and the HVHF SWPPP), including effective implementation, operation and maintenance; recordkeepting; and

inspections. The Construction SWPPP must include erosion and sediment control practices and post-

construction control practices. The HVHF SWPPP must include the applicable BMPs for HVHF operations,

which includes the requirements for certification under Section 750-3.6. Additionally, Section 750-3.7 includes

requirements for partial site reclamation, implementation of a Spill Prevention Control and Countermeasure

plan, and plugging and abandonment of gas wells prior to termination of a SPDES permit for HVHF operations.

Section 750-3.8 details the monitoring, recording and reporting requirements for a SPDES permit for

HVHF operations. Monitoring includes: stormwater discharges; volume of water used at the well site; volume

of HVHF and sanitary wastewater generated; amount of chemical additives used in HVHF operations.

Section 750-3.9 details the requirements for the renewal of an existing SPDES permit for HVHF

operations.

Section 750-3.10 details the bases upon which the department may deny, suspend, or revoke an existing

SPDES permit for HVHF operations. The conditions are necessary to protect water resources by ensuring the

Department has the maximum capability to enforce the SPDES permit for HVHF operations and associated

regulations.

Section 750-3.11 addresses a general SPDES permit for stormwater discharges associated with HVHF

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operations (HVHF general permit). This section includes a detailed list of where HVHF operations are

ineligible for coverage and would require an individual SPDES permit, including HVHF operations within: 500

feet of, and including, Principal Aquifers; and 300 feet of wetlands, perennial or intermittent streams, storm

drains, lakes, or ponds. This section also includes instances where HVHF operations are also ineligible for

coverage under a general SPDES permit consistent other department stormwater general permits.

Where an individual review by the Department is required, such allows a more focused view on water

resource protection. Moreover, Section 750-3.11 details the requirements for obtaining coverage under an

HVHF general permit, such as: filing of a complete Notice of Intent; and compliance with the regulatory

requirements of 750-3.6. Additionally, Section 750-3.11 includes the procedures for administration of an

HVHF general permit (e.g. duration; transfer of coverage; renewal; denial, suspension, and revocation; fees; and

termination). Section 750-3.11 also includes the authority for the Department to issue a stop work order. These

provisions are necessary for the protection of water resources and for an HVHF general permit to regulate the

category of discharges, which are controlled by the same set of requirements.

Section 750-12 details the requirements for the permittee to demonstrate that all HVHF wastewater will

be treated, recycled or otherwise disposed of over the projected life of the well (Fluid Disposal Plan). This

section details the requirements for disposal options, including: disposal at publicly owned treatment works;

disposal at privately owned industrial treatment facilities; on-site treatment and recycling; deep well injection;

disposal in accordance with the terms of a Department-approved beneficial use determination. The conditions

are necessary to protect the water resources by ensuring that there are no contaminated discharges and potential

pollutants are properly managed.

Lands and Forests, Fish, Wildlife and Marine Resources:

The SGEIS indicates that it does not apply to New York State Forest Preserve lands given the

constitutional restrictions applicable to such lands. Article XVI, section 1 of the State Constitution provides

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that Forest Preserve lands "shall not be leased, sold or exchanged, or be taken by any public or private

corporation." Since the Department cannot lease such lands for oil and gas development, there is no need to

consider such lands in the regulations with respect to HVHF.

The proposed regulation to prohibit the activity of HVHF on State owned lands under the Department’s

jurisdiction and administered by the Division of Lands and Forests and the Division of Fish, Wildlife and

Marine Resources conforms the legislative objectives of acquiring such lands for forest and wildlife

conservation, watershed protection, preserving unique ecological communities and providing recreational

opportunities found in the New York State Constitution, Article XIV, Section 3, and ECL Sections 9-0105, 9-

0301, 9-0501, 9-0507, 11-2101, 11-2103, and 45-0117.

This prohibition is in keeping with the specific legislative objective of ECL Section 9-0507 that the

Department issue oil and gas leases under such terms and conditions that the exercise of such leaseholds rights

shall not interfere with the operation of such reforestation areas for the purposes for which they were acquired

and as defined in Section 3 of article XIV of the Constitution.

Thus, while ECL 9-0507 authorizes oil and gas development on these lands, this development is

secondary to “the purposes for which they [reforestation areas] were acquired and as defined in Section 3 of

article XIV of the Constitution,” and such development cannot interfere with their primary Constitutional

purpose. It is reasonable, therefore, for the Department to determine that the surface disturbance associated

with HVHF is not in keeping with the primary purpose of acquiring and managing these lands. The prohibition

of surface disturbances associated with HVHF will serve to protect the ecological communities and recreational

opportunities for which State forests were established.

Article XIV, Section 4 of the State Constitution provides the policy of the state is to “conserve and

protect its natural resources and scenic beauty” and directs the legislature to provide for the acquisition of lands

and waters outside the Forest Preserve with exceptional natural beauty, wilderness character, or geological,

22

ecological or historical significance, and directs that such lands be dedicated into a State Nature and Historical

Preserve. Article XIV, Section 4 further directs that such lands “shall not be taken or otherwise disposed of

except by law enacted by two successive regular sessions of the legislature.” In keeping with these principles,

in 1972 Governor Nelson A. Rockefeller signed into law the State Nature and Historical Preserve Trust (the

“Trust”) (see ECL Article 45), declaring “the Trust will serve as a vehicle for State action in accordance with

the mandate of the Constitution to preserve and protect lands unique in historical, geological and ecological

significance.” ECL Section 45-0117(3) states that lands held under this provision are to be maintained for their

“highest, best and most important use,” including, but not limited to, “maintaining plants, animals and natural

communities,” and to “provide the public with passive recreational opportunities including, where appropriate,

fishing, hunting and trapping, or commercial fishing opportunities that are compatible with protecting the

ecological significance, historic features and natural character of the area.”

Finally, as stated above, ECL Section 11-2103 empowers the Department to acquire or receive lands

“for the purpose of establishing and maintaining public hunting, trapping and fishing grounds.” As its title

indicates, the focus of Title 21 -- Conservation Areas and Facilities; Private Refuges and Posted Lands -- is to

manage and conserve the area in a manner “calculated to promote the public interest” in wildlife activities. See

ECL Section 11-2101. The Department’s enumerated powers all relate to managing the public’s recreational

use of these lands. Indeed, while ECL Section 11-2101(2) permits the removal of “trees and other products,”

such removal should be “calculated to produce the optimum conditions for fish and wildlife.” Many of these

Article 11 lands have additional Federal restrictions on their use because they were purchased with Federal

funds. Funds provided under the provisions of the Pittman-Robertson Wildlife Restoration and Dingell-Johnson

Sport Restoration Acts (50 C.F.R. Section 80) require that land acquired be suitable for “wildlife habitat or

public access” for hunting, fishing or other wildlife-oriented recreation. See 50 C.F.R 80.50(4); 50 C.F.R.

80.51(b)(1). Thus, the clear intent of the State legislature and Congress was to empower the Department to

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acquire and manage these Article 11 lands in manner that is consistent with the public’s wildlife-oriented

recreational use of the lands.

3. NEEDS AND BENEFITS

The proposed revisions to Parts 550 through 556 stem from the need to update the Department’s existing

regulations to reflect the current practices of the Department and industry. As detailed above, proposed

revisions to the Department’s existing oil and gas regulations will reflect changes made by the legislature in

Chapter 386 of the Laws of 2005 and Chapter 376 of the Laws of 2008 and will improve regulatory conditions

in the state by, among other things: ensuring that well operators obtain adequate financial security to cover the

cost of plugging deep wells; providing the regulated community with sufficient time to commence operations;

and specifying the minimum requirements for properly plugging and abandoning a well.

The new Part 560 is proposed to respond to applications to drill HVHF wells, in some cases to target the

Marcellus Shale. The Marcellus Shale formation is attracting attention as a significant new source of natural

gas production. The Marcellus Shale extends from Ohio through West Virginia and into Pennsylvania and New

York. In New York, the Marcellus Shale is located in much of the Southern Tier stretching from Chautauqua

and Erie counties in the west to the counties of Sullivan, Ulster, Greene and Albany in the east.

The potential significant risks and impacts HVHF poses to New York’s water resources, ecosystems,

and air quality, as well as the impacts of HVHF on communities where these wells are expected to be drilled,

necessitated a thorough review and revision of existing regulations to ensure the proper administration and

regulation of these practices. The Department has identified regulatory revisions that will establish by rule

some of the mitigation measures and other aspects of the 2011 rdSGEIS, and associated public review process,

through a mechanism that will further inform and serve the public and regulated community. These regulatory

revisions will supplement the Department’s ability to monitor and enforce certain measures identified in the

2011 rdSGEIS, and associated public review process, for the protection of water resources, and will, at the same

24

time, update some of the Department’s regulations to reflect technological advances and current industry

practice.

State-owned lands play a unique role in New York’s landscape because they are managed under public

ownership to allow for sustainable use of natural resources, provide recreational opportunities for all New

Yorkers, and provide important wildlife habitat and open space. Given the level of development expected for

multi-well horizontal drilling, it is anticipated that there will be additional pressure for surface disturbance on

state-owned lands. Surface disturbance associated with gas extraction could have an impact on habitats

contained on the state-owned lands, and recreational use of those lands.

The proposed regulations prohibiting HVHF on State owned lands are necessary to protect the natural

resource values of State-owned lands, and to ensure that the State fulfills the purposes for which State Forests,

State Wildlife Management Areas, and State Parks were created. This prohibition does not include accessing

subsurface resources from adjacent private lands; thus the State and industry will be able to realize the

economic benefit of subsurface resources. Furthermore, the proposed rule would not prohibit the siting of

pipelines on state-owned lands because pipelines would not be considered associated with the drilling of a

natural gas well. However, a determination to permit the siting of a pipeline would be subject to its own site-

specific review. With that restriction in place, the Department believes that impacts to State lands from HVHF

would be minimized.

The need for all of these regulatory revisions and additions stems from observations of the experiences

in other states where HVHF is employed, as well as the statutory authority provided in the ECL discussed

above. Many benefits associated with HVHF have been realized, such as increased private and public revenues.

However, the use of HVHF also raises potentially significant adverse impacts to the environment. DEC

proposes these regulations as a means to maximize environmental impacts and costs to the public and to

maximize the benefits of natural gas extraction.

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Benefits of the adoption of these regulations would accrue to the environment as well as the public. The

regulations will provide for a tempered and balanced use of both the surface environment and the natural gas in

the subsurface. The regulations promote a greater level of environmental protection than would be the case

without the regulations. Greater environmental protection includes minimizing the probability and risk of

uncontaminated aquifers and drinking water wells, streams and surface waters, and maintaining the passive use

of natural resources, amongst others.

4. COSTS

Costs to Industry:

The costs to the regulated community for the proposed regulations will generally not differ substantially

from the potential costs that the regulated community should have expected from the mitigation measures

and/or permit conditions that have been identified in the dSGEIS. In January 2012, the Independent Oil and

Gas Association of New York (IOGA) submitted cost estimates for the permitting and planning processes

proposed by the 2011 rdSGEIS. IOGA estimates that the costs of complying with the mitigation measures in the

Revised dSGEIS, which formed the basis for nearly all of the proposed rules, ranges from approximately

$400,000 for the first well drilled on a pad in the least-complex case to approximately $1,700,000 for the first

well drilled on a pad subject to the Delaware River Basin Commission (DRBC)’s jurisdiction in the most

complex case. Subsequent wells drilled on these pads would be must less expensive according to IOGA,

ranging from approximately $50,000 to $440,000. IOGA provided a spreadsheet detailing the costs predicted by

IOGA for the various permits and plans required.

The Department conducted its own limited cost assessment, and found that, with respect to at least two

categories of cost estimates, IOGA’s estimates were excessive and speculative. IOGA estimated that $55,000

would be required for quarterly and annual stormwater sampling and reporting at an HVHF well. The

Department believes these costs estimates are significantly overestimated. The Department estimated the cost,

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utilizing best available information, at less than $1,000 per stormwater sample, and the Department anticipates

that the number of stormwater samples required for each HVHF well will be far less than fifty. Additionally,

IOGA estimated that baseline residential water well sampling and analysis would cost $5,000 for an initial well

and $3,500 for each subsequent well on a pad. Estimates from the New York State Department of Health

regarding projected costs for laboratory analysis range from $350-450 per water well sample. The Department

anticipates that the number of water well samples required for each HVHF well will be far less than ten,

meaning that IOGA’s estimated costs in this category are exaggerated. Also note that DRBC has not finalized

its regulations, meaning that IOGA’s estimates for costs associated with wells in DRBC’s jurisdiction are

speculative at this point and may be similarly exaggerated.

Unfortunately, despite repeated requests by the Department to industry to provide additional cost of

compliance information, industry has refused to provide the Department with any additional cost information.

Furthermore, the Department has attempted to locate additional cost estimates for the proposed rules from

federal agencies. The Environmental Protection Agency (EPA) website contains cost projections for air

emission standards for the oil and gas industry finalized in April 2012, which should give industry a sense of

projected costs for some of the air-related mitigation measures detailed in the SGEIS. Beyond that, the

Department’s review of EPA’s available resources did not result in any additional guidance on cost projections

for the proposed rules. To the extent that these proposed revised regulations go beyond the measures identified

in the 2011 rdSGEIS, there may be additional minor costs of compliance to the regulated community.

In addition, the use of a general permit for stormwater management developed specific for HVHF

operations will reduce regulatory fees below what would be required if individual SPDES permits were issued.

The HVHF general permit also require less burdensome administration, and potential permit conditions, than

would be required under an individual SPDES permit, which result in a cost saving.

To the extent the proposed regulatory prohibition on State-owned lands might render some gas resources

27

unavailable, there could be potential lost opportunity for industry and leaseholders. In addition, costs to such

leaseholders could be driven up if they choose to acquire surface access outside State–owned lands.

Costs to the Department and the State:

The adoption of these revised regulations will create additional costs for several state agencies. It can be

expected that the most significant costs would be incurred by the Departments of Environmental Conservation

(DEC), Health (DOH), Transportation (DOT), Public Service (DPS) and Agriculture and Markets.

Cost increases for DEC are based on its prior experience with oil and gas drilling and from the

experience of other states, for example Pennsylvania. The majority of costs are expected to be personal service

costs – the need for additional staff to carry out the large number of activities relating to permits. There are

numerous activities that will need to be addressed by DEC staff to allow HVHF exploration of low-permeability

reservoirs such as the Marcellus and Utica Shale. These activities fall into three broad categories: permitting,

compliance/monitoring, and enforcement. Additionally, a host of support services would be needed, such as

indirect and information services. These activities will be carried out by close coordination and without

duplication of services by a majority of DEC divisions including Mineral Resources; Water; Environmental

Permits; Air Resources; Environmental Remediation; Fish, Wildlife and Marine Resources; Office of General

Counsel; Law Enforcement; Hearings and Mediation Services; Information Services; and Lands and Forests.

The list of responsibilities is extensive. The discussion that follows provides an overview of DEC’s most

heavily impacted divisions and does not include each division listed above.

The Division of Mineral Resources (DMN) is the primary division charged with permitting and

overseeing oil and gas drilling in New York. DMN’s Bureau of Oil and Gas currently employs permitting staff

consisting of 8 full-time-equivalent (FTE) staff in the Central Office plus 7.7 regional FTEs. The new

requirements and standards for HVHF are significantly more rigorous and complex than traditional well drilling

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permit conditions. DMN staff statewide are responsible for the new, more complex application review, drafting

permit conditions and inspections. DEC estimates it will take approximately 175 hours to conduct technical

reviews for each permit for a well using HVHF. This work time estimate includes site visits to review pre-

construction of wells, construction, drilling, casing and hydraulic fracturing operations.

Staff is also needed for additional activities to support oversight of Marcellus and Utica Shale

development. These activities include training, supervision, compliance and enforcement, data management

support and, with the Office of Hearings and Mediation Services and the Office of General Counsel, conducting

well spacing and compulsory integration hearings.

Many of the potential impacts associated with HVHF relate to water: the amount and source of water

needed to develop the Marcellus and Utica Shales; the handling and disposal of wastewater generated; and the

management of stormwater. Handling these various aspects will require several types of programs, including

State Pollution Emission Discharge System (SPDES) permitting, management and permitting of water

resources, enforcement and compliance, and water quality monitoring. Accordingly, the Division of Water

(DOW) in close consultation with DMR will have a significant regulatory oversight and enforcement role as

HVHF moves forward.

The major areas in the Division of Environmental Remediation (DER) that would be affected by the

permitting of natural gas drilling using HVHF include: the issuance of waste transporter permits; the Spill

Response Program; the Radiation Program; and the Petroleum and Chemical Bulk Storage Program.

DEC’s Office of General Counsel (OGC) has several roles related to natural gas well drilling, which will

increase with the introduction of HVHF. Attorneys would support development of each of the divisions’

responsibilities and programmatic framework prescribed in the SGEIS. These areas include issues related to the

breadth of DEC’s jurisdiction over HVHF - site preparation, drilling, waste hauling, and wastewater disposal.

OGC will assist the divisions to address noncompliance with permits and violations of environmental laws

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resulting from well drilling activities. OGC attorneys would also be heavily involved in well spacing and

compulsory integration hearings. DEC would need both regional and Central Office attorneys to handle

permitting and enforcement cases, provide legal advice to regional program staff and coordinate policy issues,

litigation and case management.

Costs are also expected across other state agencies. DOH will incur costs investigating possible public

health issues. DOH would also be expected to have a maintain its significant role in human exposure and risk

assessment, protection of drinking water supplies, toxic substance assessment, handling of NORM, possibly

conducting population health studies, and providing health information and education.

In conjunction with DEC, DOT would review transportation plans that drillers would submit with well

applications detailing the proposed routes for truck traffic, an assessment of the road conditions on such routes,

and whether any local road use agreements are in place. DOT would require additional staff resources to

review those transportation plans and consult with DEC on their sufficiency. Additional staff would also be

needed to assess and implement potential mitigation measures on state roads in the event HVHF impacts are

identified; to undertake increased oversight for access to state highway rights-of-way, permitting for oversize

and weight trucks, and commercial vehicle inspection and enforcement.

The Public Service Commission and DPS staff are involved in all aspects of natural gas transmission

pipelines from siting and construction to ensuring the safe operation of the line after it is built. All lines over

one thousand feet long and operating at a pressure of 125 psi or greater are subject to the Commission’s

jurisdiction. Additionally, any related facilities such as compressor stations are subject to review and approval

by the Commission.

Cost impacts for Agriculture and Markets expected from these regulations would most likely be focused

in the Agricultural District Program. Most counties in New York State have placed agricultural land in state-

certified agricultural districts, which are managed by the New York State Department of Agriculture and

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Markets. Farmlands within agricultural districts are provided legal protection, and farmers benefit from

preferential real property tax assessment and protection from restrictive local laws, government-funded

acquisition or construction projects, and private nuisance suits involving agricultural practices. Article 25-AA

of Agriculture and Markets Law authorizes the creation of local agricultural districts pursuant to landowner

initiative, preliminary county review, state certification, and county adoption.

The specifics and magnitude of actual costs that may be incurred by DEC and other state agencies

cannot be estimated at this time. Based on DEC’s experience and existing program costs and examination of

programs in other states, the implementation of these regulations can be expected to require a significant staff

increase from the existing staffing levels of DMR and increase the need for additional staff to all the other

divisions listed, as well as create a need for significant staffing increases in the affected regional offices.

The costs of other agencies can be expected to be significant but lower, as the bulk of activities are the

responsibility of the DEC.

Costs to Local Governments:

This proposal will also result in increases in costs for local governments. See the discussion of local

government mandates below.

5. LOCAL GOVERNMENT MANDATES

This proposal will not directly impose any significant service, duty or responsibility upon any county,

city, town, village, school district or fire district. This proposal does not directly mandate the expenditure of

funds by any sector of local government. A primary responsibility placed on local governments through this

proposal will be to monitor requirements the proposal imposes on operators and owners in the HVHF process,

to ensure that health, safety and the environment are adequately protected.

An aspect of this proposal requires operators to notify county emergency management offices or fire

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districts of a HVHF well’s location, the potential hazards involved prior to drilling a well, the first occurrence of

flaring while drilling, prior to HVHF and prior to flaring for well clean-up, treatment or testing. The

coordination between operators and local governments on emergency response is essential to properly respond

to environmental and health emergencies at well sites related to spills, blow-outs or any other accidents. This

notification and coordination process will require some amount of resources at the local government level.

There are a number of substantial indirect effects on local governments. One aspect of this proposal

requires operators to test private residential water wells. The testing results then have to be shared with the

owner of the water well and provided to NYSDOH. This testing occurs both before and after wells are drilled

and fractured. County health departments may need to respond to issues with these residential water wells that

may arise as a result of testing. Those costs will be complaint driven and cannot be quantified at this time.

An element of this proposal allows operators to dispose of flowback water and production brine through

publically owned treatment works (POTWs) if the operators meet certain requirements. POTWs have the

discretion whether or not they wish to accept this water. If POTWs decide to accept this water, they must

perform a headworks analysis in order to ensure the POTW can handle the wastewater without upsetting their

system or causing a problem in the receiving water. No municipality is being forced to accept HVHF

wastewater for disposal, so no mandated costs should be associated with such activities. It is assumed the

POTWs would only accept the HVHF wastewater if sufficient fees could be generated to compensate for any

costs.

The use of HVHF in the state may lead to increased demand for local services, such as emergency

response needs. In addition, heavy truck traffic will result in local costs for road maintenance.

It is projected that HVHF activities would result in a substantial increase in economic activity in the

affected areas and also result in a substantial increase in tax revenues to the state and to localities. These

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revenues are expected to compensate for the types of responsibilities on local governments which may result

from approval to utilize HVHF, as discussed above.

6. PAPERWORK

The proposed rules include new paperwork requirements for all well operators, including the need to

notify and receive approval to re-fracture a previously permitted well. The draft revised regulations also require

well operators to provide a Well Drilling and Completion Report for any break in operations lasting longer than

thirty days. The new Part 560 will also add numerous application and reporting requirements specific to

HVHF. However, the Department intends to develop new forms to simplify and standardize reporting

requirements to ease the paperwork requirements imposed by the proposed regulations.

The draft regulations will also require certain documentation to be submitted to the Department pursuant

to for a SPDES permit for stormwater discharges associated with HVHF operations. However, since the

majority of HVHF activities would be done pursuant to an HVHF general permit, using standardized forms, less

paperwork will be generated then required by an individual SPDES permit.

7. DUPLICATION

This proposal is not intended to duplicate any other federal or State regulations or statutes. There is no

federal regulatory program covering HVHF, and Article 23 of the ECL and its associated regulations govern oil

and gas extraction in New York State.

ECL Article 17 provides DEC with additional jurisdiction beyond that contained in Federal Law. In

addition, DEC’s program has been approved pursuant to the Federal Clean Water Act to act in lieu of EPA in

New York State.

8. ALTERNATIVE APPROACHES

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The Department examined the no regulatory action or “no-action” alternative, in which mitigation

measures and other requirements described in the findings statement for the HVHF environmental review

process would stand-alone to direct these operations. Under this alternative, the Department would still have

the ability to enforce these mitigation measures and other requirements through the permit process. The

Department also would still have discretion in the permitting process, to determine, for example, not to permit

HVHF on State-owned lands.

However, the no-action alternative would create uncertainty for the regulated community and the public

because controls over HVHF activities would not become a part of state law. In the event that litigation over

the environmental review process for HVHF restricts the Department’s ability to impose certain mitigation

measures, the no-action alternative would restrict the Department’s ability to impose similar controls that would

properly be part of a regulatory framework. Furthermore, during the environmental review process for HVHF,

the Department received a significant number of comments urging the Department to make revisions and

additions to its current regulatory framework to cover HVHF activities. The no-action alternative does not

fulfill the Department’s needs and results in significant uncertainty.

Another alternative the Department has considered is the denial of permits for HVHF in New York

State. This alternative would fully protect the environment from any environmental impacts associated with

HVHF but it would also eliminate all of the economic benefits that could be generated by the activity. This

alternative also contravenes New York State’s declaration of policy in Article 23 of the ECL to develop oil and

gas resources that will maximize the ultimate recovery of those resources. A more detailed explanation of this

alternative is discussed in Chapter 9 of the Revised dSGEIS for HVHF.

The Department prefers the current proposal because it imposed stringent and certain conditions for

environmental protection, provides a consistent and even-handed regulatory framework for HVHF operations,

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and allows the potential economic benefits of the efficient extraction of natural gas for the Marcellus and Utica

formation.

9. FEDERAL STANDARD

As stated above, there is no federal regulatory framework over HVHF, in April 2012, EPA finalized air

emission standards for the entire oil and gas industry.

Similarly, there is no applicable Federal standard for discharges to groundwater, or groundwater

protection. Therefore, the proposed amendments exceed minimum federal government standards because New

York’s Environmental Conservation Law Article 17 provides DEC with additional jurisdiction to protect

groundwater from adverse impacts. This is necessary because all groundwater in New York State is classified

as potable/drinkable water. There are applicable Federal standards for stormwater discharges. New York’s

stormwater program meets or exceeds all federal requirements, and New York State’s program is authorized

under the Federal Clean Water Act to act in lieu of EPA in New York State.

10. COMPLIANCE SCHEDULE

The regulated community will be required to comply upon enactment of the proposed regulations.

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6 NYCRR Parts 52, 190, 550-556, 560, and 750 HIGH-VOLUME HYDRAULIC FRACTURING

REVISED JOB IMPACT STATEMENT

The New York State Department of Environmental Conservation (Department) proposes to revise 6

NYCRR Parts 52, 190, 550-556, 560 and 750. The regulations will apply statewide. The Department does not

expect the proposed regulations to have a negative impact on jobs and employment opportunities in the state.

The proposed revised rules will amend the Department’s existing regulations and will add new

regulations to address the use of high-volume hydraulic fracturing (HVHF) as a method to facilitate production

of natural gas from wells permitted by the Department. The Department is currently involved in a multi-year

environmental review of HVHF. As a result of this process, the Department has identified a number of

application requirements and mitigation measures that are expected to be uniformly applied to all HVHF wells

to ensure such wells are drilled and operated properly. The proposed revised rules will supplement the

Department’s ability to monitor and enforce certain measures identified in the Department’s revised draft

Supplemental Generic Environmental Impact Statement (2011 rdSGEIS), and will, at the same time, update

some of the Department’s regulations to reflect technological advances and current industry practice.

Nature of Impact. The approval of permits to drill natural gas wells and produce from low-permeability

reservoirs, such as the Marcellus and Utica Shales, utilizing horizontal drilling and HVHF will promote

economic activity. The proposed revised rules, implemented in combination with the Final SGEIS, once issued,

will have a positive impact on jobs and employment opportunities for such businesses as waste haulers,

construction firms and providers of lodging, food and other services. Positive impacts will be created through

direct employment, induced employment and indirect effects. This impact is expected to be concentrated in the

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counties where the Marcellus and Utica Shales are more likely to be commercially producible. Lesser though

still positive impacts may also be experienced in adjacent localities and statewide.

Categories and Numbers Affected. The proposed revised rules themselves will not negatively affect

employment opportunities, and the activities guided by the proposed revised rules will create jobs. Approval to

utilize HVHF will provide significant economic benefits to the State. Section 6.8 of the 2011 rdSGEIS provides

a detailed discussion of the potential economic, population and income impacts that may accrue if the use of

HVHF is approved. Based on industry estimates of potential drilling activity, and after applying certain

assumptions about the amount of activity that could proceed under the 2011 rdSGEIS, the Department estimates

that approval of HVHF could bring as many as 6,198 jobs assuming a low rate of development. This figure is

an estimate of the total number of direct jobs associated with construction and operation of well pads at the

lower end of potential activity.

Assuming an average rate of development, the number of direct jobs could reach 24,795 full time

equivalents. The 2011 rdSGEIS also discusses the potential employee earnings associated with HVHF and the

number of indirect jobs that could be created as a result of approval to use HVHF in the State. The 2011

rdSGEIS also contains a detailed discussion of the tax revenue which may result from production associated

with HVHF. Section 6.8 of the 2011 rdSGEIS should be consulted for a more detailed summary of the potential

economic benefits associated with HVHF, which was the focus of the Department’s review under the State

Environmental Quality Review Act (SEQRA).

Regions of Adverse Impact. There are no regions of the State expected to be negatively impacted from

the proposed revised rules. Revisions to the Department’s existing regulations for natural gas drilling are

intended to modernize the regulations, to make the rules consistent with current Department and industry

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practices. The proposed rules to address HVHF are intended to promulgate mitigation measures identified by

the Department during the SEQRA process, which will apply statewide.

Minimizing Adverse Impact. The proposed revised rules are not expected to have an adverse impact on

jobs and employment. The Department already regulates the drilling of natural gas wells and the proposed

rules, while adding new regulatory requirements applicable to HVHF, will lead to new employment

opportunities in some areas of the state and will have positive impacts on both income and employment levels.

Having the rules in place will allow for a more consistent level of development, which will be the basis for

longer-term employment. Having the rules in place will also allow those jobs that rely on other natural

resources and the environment such as tourism and forestry to remain viable.

Self-employment Opportunities. Drilling a natural gas well where HVHF is planned requires extensive

capital. Therefore, companies directly impacted by the proposed rules are not expected to involve many self-

employment opportunities. However, there will be opportunities for self-employment for supporting industries

like waste hauling, water hauling, cement mixing, construction, lodging, and food services. There may also be

opportunities for self-employed consultants to advise well operators on how to comply with the proposed

revised rules.

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REVISED REGULATORY FLEXIBILITY ANALYSIS FOR

SMALL BUSINESSES AND LOCAL GOVERNMENTS

The New York State Department of Environmental Conservation (Department) proposes to revise 6

NYCRR Parts 52, 190, 550-556, 560 and 750. The purpose of the proposed revised rulemaking is to amend the

Department’s oil and gas regulations to modernize existing regulations to reflect current Department and

industry practice and to add new regulations to the Department’s state lands, mineral resources, and water

regulations to address the use of high-volume hydraulic fracturing (HVHF). The Department is currently

involved in a multi-year environmental review of HVHF. As a result of this process, the Department has

identified a number of application requirements and mitigation measures that are expected to be uniformly

applied to all HVHF wells to ensure such wells are drilled and operated properly.

The proposed revised rules will supplement the Department’s ability to monitor and enforce certain

measures identified in the Department’s revised draft Supplemental Generic Environmental Impact Statement

(2011 rdSGEIS), and will update some of the Department’s regulations to reflect technological advances and

current industry practice. The Department’s review of HVHF under the State Environmental Quality Review

Act (SEQRA) has already been the subject of two public comment periods (2009 and 2011) and the Department

will receive further public comments on these proposed revised rules.

Effect of rules. These proposed revised rules will not have substantial adverse effects on small

businesses and local governments. The proposed revised rules will apply to any well operator who intends to

utilize HVHF to produce natural gas from wells permitted by the Department. This will, for the most part,

involve large national and international corporations. Approval of well drilling permits where HVHF is planned

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will create opportunities for small businesses to engage in activities such as waste hauling, water hauling, basic

construction services (e.g. land clearing and grading), as well as lodging, food and other personal services.

This revised proposal does not directly mandate the expenditure of funds by any sector of local

government. Although the acceptance of wastewater will involve some costs, those costs are expected to be

offset by the income generated by acceptance of the waste. In addition, one of the measures contained in the

proposed rules will require well operators to conduct baseline water well testing. Results of water well testing

may increase complaints to the county health department regardless of whether contamination is pre-existing or

attributed to nearby HVHF wells. These costs are speculative and cannot be quantified. Approval of HVHF is

also expected to impact local roads, leading to increased maintenance costs. To mitigate this impact the

proposed revised rules require an applicant for HVHF to submit a transportation plan detailing proposed routes,

estimated number of truck trips and local road conditions, and such plan will assist local government to respond

to local infrastructure needs. Well operators will also be encouraged to engage local government early in the

planning process by entering into road use agreements, so that both the regulated community and local

governments can prepare for the potential impacts of HVHF. The 2011 rdSGEIS contains a detailed analysis of

the socioeconomic impacts associated with approval to utilize HVHF.

Compliance requirements. The regulated community, which is the main focus of the proposed revised

rules, are well operators who plan to utilize HVHF to facilitate production of natural gas wells. Well operators

capable of acquiring sufficient mineral rights to enable them to apply for a Department permit to utilize HVHF

are typically well funded national and international companies. The costs to the regulated community for the

proposed revised regulations related to HVHF will not differ substantially from the potential costs that the

regulated community should have expected from the mitigation measures and/or permit conditions that have

been identified in the 2011 rdSGEIS.

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Certain aspects of drilling a well, such as clearing the site to construct the well pad and securing enough

water to use during fracturing operations will likely involve some small businesses. The proposed revised rules

do not impose substantial costs on small business, with costs limited to paperwork requirements. To the extent

that small businesses apply for a permit to drill a well utilizing HVHF, they are required to comply with the

same permitting requirements as other regulated entities.

In situations where a small business controls the mineral rights in an area where HVHF may be used,

and such small business enters into a joint operating agreement with the well operator or elects to participate in

the operation through the Department’s compulsory integration process, the proposed revised rules will increase

the costs of participating in the operation. In such cases, the cost of complying with the proposed rules will still

fall largely on the well operator since the well operator is required by the Environmental Conservation Law to

control a requisite percentage of the mineral rights in the spacing unit before the well operator is allowed to

apply for a permit to drill. The new application, reporting and operating requirements proposed to be added as

new, revised Parts 560 and 750-3 are identified by the Department as necessary measures to ensure HVHF wells

are drilled and operated properly and to ensure all wastes generated during well construction, hydraulic

fracturing and production are handled appropriately.

Local governments are not required to take any affirmative action under the proposed revised rules.

However, municipalities that operate publicly owned treatment works (POTW) may elect to accept wastewater

from HVHF operations for disposal. POTWs must have a DEC-approved pretreatment or mini pretreatment

program for accepting any HVHF wastewater and must notify DEC if they plan to receive wastewater prior to

acceptance. POTWs are required to perform a headworks analysis to ensure they can handle the wastewater

without upsetting their system or causing a problem in the receiving water. While there are costs associated

with the headworks analysis and securing DEC approval of such, the costs may be offset by a disposal fee for

allowing disposal of the HVHF wastewater at their facility. Small businesses that operate privately owned

industrial treatment facilities are not required to take any affirmative action under the proposed revised rules.

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However, small businesses that operate such treatment facilities may elect to accept wastewater from HVHF

operations for disposal, and will be subject to similar requirements and costs. Therefore, the costs associated

with complying with the proposed revised rule will not vary across the state or in rural areas, since the decision

to accept wastewater from HVHF wells is voluntary.

Professional services. Local governments are not required to take any affirmative actions under the

proposed revised rules. However, in order to be responsive to situations that could arise, local governments

may want to proactively retain professional services to assist with emergency response and traffic control in

certain circumstances. It is not anticipated that small businesses associated with high-volume hydraulic

fracturing will need to enter into contracts for professional services to comply with these proposed revised

regulations.

Compliance Costs. For small businesses and local governments that are actively participating in an

activity associated with HVHF operations, the compliance costs for the proposed revised rules will be

associated with: additional paperwork requirements for waste tracking; additional paperwork, permitting,

testing and other costs associated with operation of a wastewater treatment plant when such small business or

local government plans to treat wastewater from an HVHF well; emergency response activities; and impacts to

county health departments who respond to complaints about water well quality. Local governments may also

incur costs associated with road maintenance. As stated above, it is not expected that small businesses or local

government will be engaged in HVHF itself. For small businesses that apply for a permit to drill an HVHF

well, revised Parts 560 and 750-3 rules will result in increased compliance costs compared to a non-HVHF well.

However, the costs are not expected to materially differ from the costs expected to implement the mitigation

measures identified in the 2011 rdSGEIS. Cost projections from the Independent Oil and Gas Association of

New York (IOGA) for complying with the 2011 rdSGEIS range from $400,000 to $1,700,000 for the first well

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drilled on a well pad. The Department conducted its own limited cost assessment, and found that, with respect

to at least two categories of cost estimates, IOGA’s estimates were excessive. Unfortunately, despite repeated

requests by the Department to industry to provide additional cost of compliance information, industry has

refused to provide the Department with any additional cost information.

Apart from the provisions in the proposed revised rules related to HVHF, the proposed revised changes

to Parts 550-556 will raise the minimum requirements to plug and abandon a well under the Department’s

jurisdiction. There have been occasions where local governments have drilled self-help wells, or wells meant to

supply gas to local buildings. There also exists the possibility that abandoned wells may exist on public lands.

Part 555 currently provides minimum plugging standards for wells; however, plugging procedures often depend

on site-specific factors such as the condition of the well and well construction methods. The proposed revisions

to Part 555 would still specify minimum standards but the proposed revisions to Part 555 would not raise the

cost of plugging a well above that which is often already required by current Department practices. The costs

associated with the new reporting requirements contained in the proposed changes to 6 NYCRR Parts 550-556

are expected to be minimal.

Economic and technological feasibility. There should be no economic or technological feasibility issues

created by the proposed revised rules. To the extent that local governments or small business may want to allow

and/or participate in a facet of HVHF operations, such could result in a substantial increase in economic activity

in the affected areas and also result in a substantial increase in tax revenues to the state and to localities.

Minimizing adverse impact. The proposed revised rules contain some measures to mitigate potential

impacts on local government, such as the need for well operators to submit a transportation plan to the

Department prior to issuance of a drilling permit. A transportation plan would assist localities in planning for

HVHF to allocate resources and initiate a dialogue with well operators. As stated above, the regulated

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community under the proposed revised rules includes large national and international corporations. Small

businesses who intend to drill an HVHF well will be subject to the same rules as larger businesses and the costs

of complying with the proposed revised rules is not expected to differ from the cost of complying with the

application requirements and mitigation measures identified in the 2011 rdSGEIS. Small businesses, such as

waste haulers and water haulers, who provide support services to well operators will have minimal costs to

comply with the rules, with costs limited to paperwork requirements (e.g., tracking waste from an HVHF well

pad to a destination for disposal or reuse).

Small business and local government participation. The Department participated in outreach to the

regulated community through the initial rulemaking process, including the solicitation of comments from

affected industry. Additionally, the proposed use of HVHF in New York has been the subject of substantial

public outreach and input over the last several years. During scoping sessions, before and after issuance of the

2009 draft SGEIS, prior to issuance of the 2011 rdSGEIS, and since the issuance of the 2011 rdSGEIS, the

Department received over 66,000 individual public comments on these documents, from postal mail, electronic

submissions, and speakers at public hearings in several of the potentially affected areas. The Department has

had multiple interactions with the regulated community, small business, and local governments on HVHF and

the quickly-evolving HVHF industry. The scope of the 2011 rdSGEIS also considered the impact of proposed

additions and revisions of the Department’s HVHF regulations, allowing for extensive participation on both the

rules and the environmental review process simultaneously. Through this proposed revised rulemaking, the

Department will provide for an additional public review and comment period.

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REVISED RURAL AREA FLEXIBILITY ANALYSIS

The proposed revised rulemaking will modify the Department of Environmental Conservation’s

(Department) existing regulations and promulgate new regulations related to the use of high-volume hydraulic

fracturing (HVHF). HVHF involves the fracturing of wells utilizing more than three hundred thousand gallons

of water as the base fluid for fracturing operations and is proposed to be used in natural gas wells permitted by

the Department. Also included in the proposed rules are updates to the Department’s oil and gas and State

Pollutant Discharge Elimination System (SPDES) regulations.

Type and Estimate of the Number of Rural Areas Affected. The proposed revisions and additions to the

Department’s regulations will apply to the use HVHF statewide; however, two formations likely to be initially

targeted for production are the Marcellus and the Utica Shales. The prospective region for the extraction of

natural gas from the Marcellus and Utica Shales has been roughly described as an area extending from

Chautauqua County eastward to Greene, Ulster and Sullivan counties, and from the Pennsylvania border north

to the approximate location of the east-west portion of the New York State Thruway between Schenectady and

Auburn. According to 2010 Census figures, all of these nearly 30 counties, except for portions of Erie, Monroe,

Onondaga, and Albany counties, would be considered rural areas. The updates to the Department’s oil and gas

and SPDES regulations will apply statewide.

Compliance with the Revised Rules. These proposed revised requirements are applicable to HVHF

activities statewide, and would not result in any disproportionate impact on the regulated community in rural

areas. The proposed rules will apply to any well operator who intends to utilize HVHF to produce natural gas

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from wells permitted by the Department. This will, for the most part, involve large national and international

corporations and the well operator’s ability to comply with the proposed rules is not expected to be affected by

the fact that a well is located in a rural area.

The proposed revised rules include recordkeeping and reporting requirements for well operators related

to: well construction; private water well testing; and well completion reporting, when an operator proposes to

use HVHF. The proposed revised changes to the Department’s existing oil and gas regulations which include: a

new reporting requirement to re-fracture an existing well; the need to file an interim completion report and

enhanced minimum plugging requirements, will apply statewide. The capital required to secure the requisite

percentage of mineral rights needed to obtain a permit from the Department, and to drill a natural gas well with

or without the use of HVHF, is substantial. Therefore, the Department does not expect public or private sector

interests in rural areas to be adversely affected by the proposed changes to the Department’s existing oil and gas

regulations. Moreover, the costs associated with notifying and receiving approval to re-fracture a well or to

submit an interim completion report are expected to be minimal. Enhancement of the Department’s minimum

plugging requirements will also not adversely affect the regulated community, as the regulations provide only

minimum standards and the Department regularly requires more stringent plugging procedures depending on

site-specific circumstances. Therefore, due to current Department and industry practices, the costs associated

with plugging a well by the either public or private sector in rural areas will not substantially change as a result

of the proposed regulations.

Another sector of the regulated community that will be impacted by the proposed rules are mineral

rights owners involved in compulsory integration proceedings administered by the Department. Compulsory

integration, governed by Environmental Conservation Law (ECL) Article 23, Title 9, is the process by which

the Department addresses un-leased mineral rights in a proposed spacing unit surrounding the well established

by the Department-issued permit to drill. In situations where a mineral rights owner elects to participate in the

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costs of developing a well where HVHF will be used, the proposed revised rules will increase the costs of

participation. In such cases, the cost of complying with the proposed revised rules will still fall largely on the

well operator since the well operator is required by the ECL to control at least sixty percent of the mineral rights

in the spacing unit that would be produced before the well operator may apply for a permit to drill. The new

application, reporting and operating requirements proposed to be added as a new, revised Part 560 to 6 NYCRR

will impact mineral rights owners. However, these requirements have been identified by the Department as

necessary measures to ensure HVHF wells are drilled and operated properly and to ensure all waste generated

during well construction, hydraulic fracturing and production are handled appropriately.

The proposed revised rules also contain testing, monitoring and recordkeeping requirements for

operators of publicly owned treatment works (POTW). Therefore, POTW operators in rural areas may be

affected by the proposed revised rules, to the extent that such POTWs accept wastewater associated with wells

where HVHF was utilized. In general, POTWs must have a DEC approved pretreatment or mini pretreatment

program for accepting any HVHF wastewater and must notify DEC if they plan to receive wastewater at their

facility before acceptance. POTWs are required to perform a headworks analysis to ensure they can handle the

wastewater without upsetting their system or causing a problem in the receiving water. While there are costs

associated with the headworks analysis and securing DEC approval of such, this may be offset by the disposal

fee that the municipality may impose for allowing disposal of the HVHF wastewater at their facility. Small

businesses that operate privately owned industrial treatment facilities are not required to take any affirmative

actions under the proposed revised rules. However, small businesses that operate such treatment facilities may

elect to accept wastewater from HVHF operations for disposal, and will be subject to similar requirements and

costs. Therefore, the costs associated with complying with the proposed revised rule will not vary across the

state or in rural areas, since the decision to accept wastewater from HVHF wells is voluntary.

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Although the Department does not expect the proposed revised rules to adversely affect the regulated

community in rural areas, the proposed rules will indirectly impact the ability of rural areas to respond to

activities associated with the approval of HVHF. Indirectly the proposed rules may require local governments

to respond to additional complaints about water well quality as well owners are made aware of water well

testing required by the proposed rules. Approval of HVHF is also expected to increase local traffic and in some

areas, increase the local population. As a result, local governments may experience increased demand on local

services, such as emergency response and local road maintenance. The 2011 rdSGEIS contains a detailed

analysis of the socioeconomic impacts associated with approval to utilize HVHF and proposed mitigation

measures.

With respect to professional services in rural areas, the proposed revised rules may require the regulated

community to hire professionals to assist in compliance activities required by the regulations. The additional

stormwater requirements and requirements for disposal of HVHF wastewater are two examples where the

proposed revised rules may require well operators to hire experts. However, the ability of a well operator to

comply with the proposed revised rules is not expected to be affected by the fact that a well is located in rural

areas.

Local governments are not required to take any affirmative actions under the proposed rules. However,

local governments may proactively retain professional services to assist with emergency response and traffic control

in certain circumstances, where approval of HVHF leads to impacts in those areas of local government.

Costs. The recordkeeping, reporting and compliance requirements included in the proposed revised 6

NYCRR Part 560 and the Part 750-3, would promulgate the application requirements and mitigation measures

identified by the Department in the SEQRA process. Therefore the costs of complying with the proposed

revised regulations pertaining to HVHF will not differ substantially from the costs of complying with the

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SGEIS. Cost projections from the Independent Oil and Gas Association of New York (IOGA) for complying

with the 2011 rdSGEIS range from $400,000 to $1,700,000 for the first well drilled on a well pad. The

Department conducted its own limited cost assessment, and found that, with respect to at least two categories of

cost estimates, IOGA’s estimates were excessive. Unfortunately, despite repeated requests by the Department to

industry to provide additional cost of compliance information, industry has refused to provide the Department

with any additional cost information.

Public entities will incur minimal costs under this revised proposal as the public sector is not the focus

of the proposed revised rules. This is no different than the public entities’ role with respect to other industries,

and public entities may be able to use increased tax and other revenue generated through HVHF activities to

offset any increased burden on services it provides.

Apart from the provisions in the proposed revised rules related to HVHF, the proposed revised changes

to Parts 550-556 will raise the minimum requirements to plug and abandon a well under the Department’s

jurisdiction. There have been occasions where local governments have drilled self-help wells, or wells meant to

supply oil or gas to local buildings. There also exists the possibility that abandoned wells may exist on public

lands. However, as described above, the proposed revisions to Part 555 would still specify minimum standards

and the proposed revisions to Part 555 would not raise the cost of plugging a well above that which is often

already required by current Department practices. The costs associated with the new reporting requirements

contained in the proposed changes to 6 NYCRR Parts 550-556 are expected to be minimal.

Minimizing adverse impact. The regulated community, which is the main focus of the proposed revised

rules, is well operators who plan to drill wells and utilize HVHF to facilitate production of natural gas.

Although natural gas wells will be located in rural areas, the proposed revised rules will not have an adverse

impact on private or public members of the regulated community in rural areas due to the location of the well.

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With respect to indirect costs on local governments in rural areas, the proposed revised rules contain some

measures to mitigate potential impacts, such as the need for well operators to submit a transportation plan to the

Department prior to issuance of a drilling permit. A transportation plan would assist localities in planning for

HVHF operations to allocate resources and initiate a dialogue with well operators. Supporting industries, such

as waste haulers and water haulers, who provide a service to well operators will have minimal costs to comply

with the rules, with costs limited to paperwork requirements (e.g. tracking waste from an HVHF well pad to a

destination for disposal or reuse).

Rural Area Participation. The Department participated in outreach to the regulated community through

the initial rulemaking process, including the solicitation of comments from affected industry. Additionally, the

proposed use of HVHF in New York has been the subject of substantial public outreach and input over the last

several years through the SEQRA process. During scoping sessions, before and after issuance of the 2009 draft

SGEIS, prior to issuance of the 2011 rdSGEIS, and since the issuance of the 2011 rdSGEIS, the Department

received over 66,000 individual public comments on these documents, from postal mail, electronic submissions,

and speakers at public hearings in several of the potentially affected rural areas. The Department has had

multiple interactions affected rural areas, which provided additional opportunities for affected rural areas to

participate in the rulemaking process. Through this proposed revised rulemaking, the Department will provide

for an additional public review and comment period.


SUMMARY OF ASSESSMENT OF PUBLIC COMMENT

This assessment summarizes and responds to the consolidated comments received on the

draft regulations for Parts 52, 190, 550-556, 560,750-1, and 750-3. The revised draft

Supplemental Generic Environmental Impact Statement (rdSGEIS) was released for public

comment on September 7, 2011. On September 28, 2011, the New York State Department of

Environmental Conservation (Department) released for public comment draft regulations

concerning high-volume hydraulic fracturing and the SPDES General Permit for Stormwater

Discharges from High-Volume Hydraulic Fracturing (HVHF General Permit). Public hearings

were held concurrently on all of these documents and the combined public comment period was

held open until January 11, 2012. In total, the Department received over 66,000 individual

public comments on these documents, from postal mail, electronic submissions, and speakers at

public hearings held in 2011.

The Department processed every comment and comments received equal consideration.

The Department broke down comment submissions into smaller, more manageable segments.

Similar segments were combined into one consolidated statement. Therefore, one consolidated

statement could represent portions of identical or similar comments received from a number of

commentors. Of the 66,000 comments, there are more than 650 consolidated statements on the

draft regulations to which the Department provided responses.

The Department received comments from many diverse groups and individuals including

mineral rights owners, federal, state and local agencies, environmental organizations, landowner

coalitions, industry representatives, and legislators. During preparation of the proposed revised

regulations, the Department incorporated suggestions made by the public (both with respect to

the proposed regulations and the 2011 rdSGEIS).

The Assessment of Public Comment presents and responds to all of the consolidated

comments. This is a summary of the most frequent comments and the Department’s responses.

In addition to comments on the proposed regulations, the Department received comments on the

substance of the regulatory supporting documents. The Department provided additional

discussion with respect to estimated costs of the regulations on industry in the revised Regulatory

Impact Statement and made changes to the other revised regulatory documents, where

appropriate.

With respect to the proposed regulations at 6 NYCRR 750-3, the majority of comments

were submitted on the following topics: setbacks; wastewater disposal; and chemical disclosure

and the alternative analysis. The majority of comments received on the setbacks were that the

setbacks are not restrictive enough to protect water resources; however, some comments stated

that the setbacks are too conservative.

Setbacks were developed as an effective risk management tool to protect water resources

in the event of a spill. In this regard, each setback reflects the magnitude of the potential risk or

harm. In developing the setbacks, the Department considered the designated use of the resource,

such as drinking water supply (and in such cases, population served).

In addition to setbacks, the revised regulations at 6 NYCRR 750-3 and the draft HVHF

General Permit propose measures to prevent spills and releases and to contain those that occur.

Specific Best Management Practices are required for all aspects of high-volume hydraulic

fracturing operations (e.g., pit construction and liner specifications; closed-loop systems in

certain instances; wastewater storage; secondary containment; peripheral berm; and emergency

and spill response plans).

Specific changes from the proposed regulations can be found in the revised regulations at

6 NYCRR 750-3.3 (prohibitions) and 750-3.11 (ineligible for coverage under a stormwater

general permit for HVHF operations, but where an individual SPDES permit and site-specific

State Environmental Quality Review Act review are required).

The Department also received numerous comments regarding the disposal of HVHF

wastewater. The proposed revised regulations at 6 NYCRR 750-3 require an approvable Fluid

Disposal Plan that identifies the ultimate disposition of HVHF wastewater and contains an

acceptable contingency plan for disposition of such fluids.

Many comments related to a Publicly Owned Treatment Works (POTW), as a disposal

option. POTWs may accept HVHF wastewater so long as the POTW is in compliance with

applicable regulations, including any necessary approvals and permits. The revised regulations

at 6 NYCRR 750-3 include requirements for acceptance of this wastewater for disposal at

POTWs. The POTW must have an Environmental Protection Agency (EPA) or Department

approved pretreatment program and must conduct a headworks analysis and receive approval

prior to applying to accept HVHF wastewater. The headworks analysis evaluates the pollutants

present in the wastewater against the capabilities of the treatment system and assesses any

potential adverse impacts to a treatment system process and the receiving waterbody. All State

Pollutant Discharge Elimination System (SPDES) permits require periodic monitoring to ensure

compliance with applicable limits to ensure water quality standards are met. A similar

demonstrable showing is required for other HVHF wastewater disposal options in New York

State (e.g. privately owned industrial treatment facilities; deep well injection).

Comments were also received on the requirements for disclosure of chemical additives

and the alternatives analysis. The analysis must include documentation to the Department’s

satisfaction that proposed alternatives exhibit reduced aquatic toxicity and pose at least s low a

potential risk to water resources and the environment as all known available alternatives. The

Department intends to provide further guidance regarding the specifics of the alternatives

analysis. Also, the revised regulations at 6 NYCRR 750-3 require that the owner or operator

maintain a list, at the well site, of the chemical additives used. All documents submitted to the

Department would be available to the public, subject to exceptions in the Freedom of

Information Law.

With respect to the proposed regulations at 6 NYCRR 52 and 190, the majority of

comments sought an expansion of the prohibition from Department administered State-owned

lands to all public lands, a prohibition of pipelines on State-owned lands. a prohibition of

subsurface access, or a prohibition of drilling on private lands adjacent to State-owned lands.

The Department received some comments opposed to the prohibition on surface disturbances

associated with high-volume hydraulic fracturing on State-owned lands.

With respect to Department administered state-owned lands, the proposed regulatory

prohibition on surface disturbances associated with high-volume hydraulic fracturing on these

lands is based, in part, upon the unique legislative protections and legal constraints applying to

these lands. This prohibition was not extended to adjacent private lands because these lands are

not subject to the same legal and legislative constraints. Similarly, the Department did not

prohibit subsurface access from adjacent private lands because subsurface access to mineral

resources underneath State lands would not be inconsistent with the purposes for which these

State lands were acquired. The Department determined that government entities having

jurisdiction over other publicly-owned lands should decide whether to prohibit high-volume

hydraulic fracturing on the surface of those lands.

Finally, with respect to pipelines, the Department does not believe that a prohibition is

necessary to ensure that State-owned lands are managed consistent with the purposes for which

they were acquired. Pipelines would be permitted on State-owned lands only if certain

provisions of the ECL are met, and in compliance with an approved Unit Management Plan.

With respect to the proposed rulemaking at 6 NYCRR 550-556 and 560, the comments

received contained critiques from various stakeholders, some stating that the regulations went

too far in regulating the proposed activity of high-volume hydraulic fracturing, while others

stated the proposed rules are too permissive. Some of these comments necessitated revisions to

the proposed rules, but the majority did not.

Several of the comments on Part 550 expressed concern over the Department’s ability to

enforce its regulations. The Department believes that there are ample existing legal mechanisms

available to the Department to enforce the proposed regulatory requirements.

Some comments on Part 551 expressed concern over the financial security requirements

related to plugging of wells and abandonment of well sites. Several commentors expressed

concern over the removal of the $2 Million cap on financial security, and others expressed

concern that financial security should cover more activities (clean up, contingency) than

plugging and abandonment. The proposed revised regulations allow for the plugging of wells

without predetermination of the associated costs, creating flexibility for the Department to

capture the true potential costs.

A few comments suggested severance taxes or other fees, but these revisions are beyond

the Department’s authority and would require legislative action.

Several of the comments on Part 552 expressed varied opinions regarding extending the

permit period to two years. The Department believes the proposed extension is warranted

because the complexity of permitting a high-volume hydraulically fractured well makes the 180

day time period unmanageable. Comments on this Part also questioned the provision for verbal

authorization of emergency operations, however, the Department believes this provision is

necessary to allow rapid responses to unexpected or non-routine situations that could impact

public health and safety and the environment. Comments also focused on the details of what

should be included in a well permit application, and in some cases suggested that requirements

specific to high-volume hydraulic fracturing should apply to all wells. The potential impacts of

other wells are effectively addressed by existing regulations and permit conditions.

Many of the comments on Part 553 expressed concern that the spacing units referenced in

the proposed regulations were too small and may result in concentrating more well pads over the

landscape and increasing the potential for habitat fragmentation. Spacing unit size is constrained

by statute. Other comments addressed proposed variance provisions or compulsory integration

(the latter of which is prescribed by statute and beyond the scope of this proposed rulemaking).

Many comments on Part 554 expressed concern over the potential for improper disposal

of waste fluids and solids. In addition to the requirements set forth in the proposed regulations,

the revised rulemaking includes a requirement that the owner or operator state in its fluid

disposal plan that it will maximize the reuse and/or recycling of used drilling mud, flowback

water and production brine to the maximum extent feasible. Furthermore, some record-keeping

requirements set forth in Part 554 have been enhanced in the revised rulemaking.

The bulk of the comments on Part 555 were on construction specifics related to casing

and well plugging requirements. Many of the comments on Part 556 expressed concern about the

potential air impacts of venting and flaring. A revision was made to the proposed regulations to

clarify the approval process for flaring that would reduce potential air impacts. Other comments

focused on the proposed Sundry Well Notice and Report form, requesting either clarification on

when it would be required or the time frames for submission. The revised rulemaking includes

time frames, a verbal approval process for sundry notice operations similar to the verbal approval

process in Part 553 and authority for the Department to suspend or terminate sundry notice

approvals for good cause.

Most comments on the proposed rulemaking were on the new Part 560 that specifically

covers high-volume hydraulic fracturing activities. The proposed rules for this Part mirror many

of the environmental mitigation measures identified during the SEQRA process. The comments

corresponded to similar comments the Department has received on the 2011 rdSGEIS, including

areas such as emergency response, transportation impacts, local government and public input,

fracturing fluid disclosure, setbacks and prohibitions, notification and reporting requirements,

water well testing requirements, cementing and casing requirements, Naturally Occurring

Radioactive Materials (NORM) and other areas.

The revised proposed regulations provide for enhanced environmental protections while

providing for efficient utilization of mineral resources. Specifically, in response to these

comments, the Department has proposed substantial revisions to the Part 560 regulations to

include: several new definitions; an enhanced application process, including a 15-day public

notice period; authority to collect SEQRA fees; enhanced chemical disclosure provisions with

website posting; an increased setback from inhabited private dwellings or places of assembly,

with a variance process; enhanced notification and records retention requirements; specified

parameters for water well testing and a requirement to report deviations from baseline; public

posting of Drilling and Production Waste Tracking Form, and post-completion fracturing fluid

disclosure; and specifics on NORM testing. Other non-substantial clarifying revisions were made

to proposed Part 560 based on comments received regarding application requirements, fluid

disposal plans, setbacks, casing and cementing requirements, site reclamation, and

recordkeeping.

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REVISED SUMMARY OF EXPRESS TERMS

The proposed revised rules include revisions and additions to the Department’s oil and gas regulations,

regulations on the management of state land and to State Pollutant Discharge Elimination System (SPDES)

permitting regulations. High-volume hydraulic fracturing involves the fracturing of wells utilizing more than

300,000 gallons of water as the base fluid.

Mineral Resources.

Several of the changes proposed for the oil and gas regulations are administrative in nature and are

necessary to update existing regulations to current Department and industry practices. Included in this category

of changes is the language proposed to be added to section 552.2, which will clarify that the expiration of a

permit to drill, deepen, plug back or convert a well does not relieve an operator from compliance with the terms

specified in a permit when the operator commences operations during the permit term. Definitions will also be

added to Part 550 for hydraulic fracturing, hydraulic fracturing fluid, true measured depth, true vertical depth,

well spud, and workover.

The proposed rules will modify section 551.6 to remove the blanket bond available to operators who

drill multiple wells and will revise section 552.2 to extend the term of a permit to drill, deepen, plug back or

convert a well from six months to two years. Section 552.3 is proposed to be modified to allow the Department

to re-issue a permit to another operator for a location that has already been permitted by the Department.

Several provisions in the proposed rules will also modernize the Department’s regulations to make them

consistent with recent statutory changes made to Environmental Conservation Law Article 23. Chapter 386 of

the Laws of 2005 made significant changes to the statewide spacing scheme for natural gas wells and the

proposed rules will incorporate some of those changes. Statutory statewide spacing provisions were also

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adopted by the Legislature in 2008. The proposed rules promulgate these changes related to shale well

development.

Additional recordkeeping requirements are included in the proposed rules, including a provision that

will require operators to file an interim completion report for any gap in drilling operations lasting longer than

thirty days. Enhancements are also proposed for Part 555, which contains standards for the plugging and

abandonment of wells under the Department’s jurisdiction. Proposed changes to section 555.5 would require

operators to obtain well logs prior to plugging to aid in determining the appropriate plugging procedures. The

proposed rules will also clarify the density of the fluid that may be utilized between plugs set in the bore hole

during plugging of the well and will clarify the reclamation requirements for the land adjacent to the surface

location of the well.

A new Part 560 is proposed to address high-volume hydraulic fracturing. Part 560 consists of seven

sections, beginning with section 560.1 which makes Part 560 applicable to all wells where high-volume

hydraulic fracturing is proposed. Section 560.1 also states that Parts 550-558 will continue to apply to the

extent not superseded by Part 560. Proposed section 560.2 contains several definitions related to high-volume

hydraulic fracturing including additive, chemical constituent, flowback, and high-volume hydraulic fracturing,

as well as definitions related to new setbacks specific to high-volume hydraulic fracturing surface activities.

Section 560.3 will promulgate many of the application requirements specified in the SGEIS, including:

the need for a blowout preventer use and testing plan; detailed mapping requirements; and disclosure of

additives proposed to be used during hydraulic fracturing including the proposed volume of each and the

proposed percent by weight of base fluid, each additive and proppants, if used. The chemical disclosure must

also identify each chemical constituent intentionally added to the base fluid and its proposed concentration.

Section 560.3 also sets out a process for Department review of permit applications, including a 15 day public

comment period. This section provides for collection of fees, including ones that may be charged for

preparation of GEISs (see 6 NYCRR sections 617.13 and 618.1).

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Section 560.4 proposes setbacks for high-volume hydraulic fracturing for surface activities, including

setbacks for wells proposed within 500 feet of a primary aquifer, private water well, domestic use spring, water

supply for crops or livestock, inhabited dwelling or place of assembly, and specified distances from certain

water resources. Section 560.4 provides that the Department may grant variances from the 500 foot setback

from a private water well, domestic use spring, or water supply for crops or livestock, and from an inhabited

dwelling or place of assembly subject to landowner and tenant consent (as applicable) where there are no

reasonable allowable alternative locations for the well pad. The Department shall impose reasonable and

necessary conditions to minimize any adverse impact.

Section 560.5 will promulgate the well testing, recordkeeping and reporting requirements in the SGEIS.

This section includes requirements for well operators to prepare an emergency response plan and notify county

emergency management offices, report non-routine incidents, and test residential water wells within a specified

distance from the proposed gas well. The regulations authorize the Department to require water well testing

after wells are completed to investigate whether drilling activities have impacted residential water well quality.

Section 560.6 contains detailed well construction and operational requirements for high-volume

hydraulic fracturing wells and separate subdivisions specify requirements for site preparation, such as the

design standards for reserve pits; site maintenance, such as secondary containment and other operational

requirements; and drilling, hydraulic fracturing and flowback, including several requirements in relation to

these activities, such as cementing and casing, monitoring during fracturing operations, storage of flowback

water, and venting and flaring requirements.

Section 560.7 includes waste management and reclamation requirements that specify how wastes

generated on the well pad should be managed and further specifying that partial and final reclamation of the

well site must be done in accordance with the plans approved by the Department.

Lands and Forests and Fish, Wildlife and Marine Resources.

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Parts 52 and 190 of 6 NYCRR will be modified to prohibit the leasing of state-owned land for surface

activities related to HVHF. The prohibition, however, will not prevent the Department from leasing state land

to allow subsurface access to the state’s mineral rights from locations adjacent to state-owned land. Nor would

the proposed rule prohibit the siting of pipelines on state-owned lands because pipeline are not considered

associated with the drilling of a natural gas well. However, a determination to permit the siting of a pipeline

would be subject to its own site-specific review.

Water Resources.

This revised rulemaking updates Section 750-1.5 to conform the existing regulation to the current

federal process for issuance of Underground Injection Control permits.

Part 750-3 will consist of twelve sections. Unless in conflict, superseded or expressly stated otherwise

in this Subpart, the provisions set forth in Subpart 750-1 and Subpart 750-2 of this Part apply to HVHF

operations.

Section 750-3.2 incorporates the definitions provided in 750-1.2 and provides additional definitions

specific for HVHF operations.

Section 750-3.3 prohibits certain HVHF activities and discharges and does not allow the issuance of a

SPDES permit for such activities or discharges. These specifically include well pads for HVHF operations:

within 4,000 feet of, and including, an unfiltered surface drinking water supply watersheds; within 500 feet of,

and including, a primary aquifer; within 100 year floodplains; within 2,000 feet of any public (municipal or

otherwise) drinking water supply well, reservoir, natural lake, man-made impoundment, or springs; within

2,000 feet of any public (municipal or otherwise) drinking water supply intake in flowing water with an

additional prohibition of 1,000 feet on each side of the main flowing waterbody and any upstream tributary to

that waterbody for a distance of 1 mile from the public drinking water supply intake; and within 500 feet of a

private water well or domestic use spring, or water supply for crops or livestock, unless the department has

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granted a variance. The distances are measured from the closest edge of the HVHF well pad.

For the purposes of obtaining a SPDES permit for HVHF operations, Section 750-3.4 states that HVHF

operations cannot commence without a valid HVHF SPDES permit.

Section 750-3.5 provides the minimum information required for the Department to determine that

groundwater or surface water quality will not be degraded by the injection of water, gas or other material

through HVHF into a well to facilitate the production of gas resources.

The requirements in Sections 750-3.6, 750-3.7, and 750-3.8 protect water resources by ensuring

necessary and adequate stormwater management practices are in place and properly operated and maintained.

The requirements of these sections also ensure water resources are protected through the application of the

Uniform Procedure Act and SEQRA.

Section 750-3.6 details the requirements for an individual HVHF SPDES permit application. This

section provides a list of the certifications required including: disclosure of chemical additives; evaluation and

use of less toxic alternatives; on-site maintenance of a list of chemical additives used; residential water well

testing; removal of HVHF wastewater from the well site; secondary containment; containment of flowback and

production brine; construction and use of reserve pits; and closed-loop system requirements. These

certifications are also regulatory requirements found in Section 750-3.7. Section 750-3.6 also requires the

proper handling and disposal of HVHF wastewater; identification of the depth of the HVHF drilling; and the

development of a comprehensive stormwater pollution prevention plan (SWPPP), which addresses the

construction, HVHF and production phases of natural gas well development through the Construction SWPPP

and HVHF SWPPP.

Section 750-3.7 details the requirements of a Comprehensive SWPPP (both the Construction SWPPP

and the HVHF SWPPP), including effective implementation, operation and maintenance; recordkeeping; and

inspections. The Construction SWPPP must include erosion and sediment control practices and post-

construction control practices. The HVHF SWPPP must include the applicable BMPs for HVHF operations,

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which includes the requirements for certification under Section 750-3.6. Additionally, Section 750-3.7 includes

requirements for partial site reclamation, implementation of a Spill Prevention Control and Countermeasure

plan, and plugging and abandonment of gas wells prior to termination of a SPDES permit for HVHF operations.

Section 750-3.8 details the monitoring, recording and reporting requirements for a SPDES permit for

HVHF operations. Monitoring includes: stormwater discharges; volume of water used at the well site; volume

of HVHF and sanitary wastewater generated; amount of chemical additives used in HVHF operations.

Section 750-3.9 details the requirements for the renewal of an existing SPDES permit for HVHF

operations.

Section 750-3.10 details the bases upon which the department may deny, suspend, or revoke an existing

SPDES permit for HVHF operations.

Section 750-3.11 addresses a general SPDES permit for stormwater discharges associated with HVHF

operations. This section includes a detailed list of where HVHF operations are ineligible for coverage and

would require an individual SPDES permit, including HVHF operations within: 500 feet of, and including,

Principal Aquifers; and 300 feet of wetlands, perennial or intermittent streams, storm drains, lakes, or ponds.

This section also includes instances where HVHF operations are also ineligible for coverage under a general

SPDES permit consistent with other department stormwater general permits.

Moreover, Section 750-3.11 details the requirements for obtaining coverage under an HVHF general

permit, such as: filing of a complete Notice of Intent; and compliance with the regulatory requirements of 750-

3.6. Additionally, Section 750-3.11 includes the procedures for administration of an HVHF general permit (e.g.

duration; transfer of coverage; renewal; denial, suspension, and revocation; fees; and termination). Section 750-

3.11 also includes the authority for the Department to issue a stop work order.

Section 750-12 details the requirements for the permittee to demonstrate that all HVHF wastewater will

be treated, recycled or otherwise disposed of over the projected life of the well (Fluid Disposal Plan). This

section details the requirements for disposal options, including: disposal at publicly owned treatment works;

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disposal at privately owned industrial treatment facilities; on-site treatment and recycling; deep well injection;

and disposal in accordance with the terms of a Department-approved beneficial use determination.

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REVISED REGULATORY IMPACT STATEMENT SUMMARY

The proposed revised rulemaking modifies Department of Environmental Conservation’s (Department)

regulations for oil and gas, the State Pollutant Discharge Elimination System (SPDES), fish and wildlife, and

state lands and promulgates new regulations related to high-volume hydraulic fracturing (HVHF).

Statutory Authority and Legislative Objectives. The Department proposes these regulations to ensure

potential environmental impacts resulting from HVHF are mitigated to the maximum extent practicable

consistent with the legislative objectives in the Environmental Conservation Law (ECL). The Department’s

general authority for the proposed revised rules is found at ECL Articles 1 and 3, which identifies the state’s

responsibility to manage water, land, fish, wildlife and air resources to assure their protection, enhancement,

and balanced utilization, without risk to health and safety.

ECL sections 23-0301, 23-0303, 23-0305, 23-0501 and 23-0503 provide specific authority for the

proposed changes to Parts 550 through Part 556, and Part 560. These provisions provide the Department with

power to regulate drilling, casing, operation, plugging, replugging, and posting of financial security for wells,

and reclamation.

Changes to the Department’s existing rules include clarifying language to Section 552.2 to specify that

expiration of a permit to drill does not relieve an operator from compliance with the permit terms once

operations have commenced; removal of the $2 Million cap on financial security; updates to statewide spacing

regulations; and enhancements to the requirements for plugging and abandonment of wells.

Part 560, applicable to HVHF wells, promulgates many mitigation measures specified in the Supplement

Generic Environmental Impact Statement on the Oil and Gas Regulatory Program (SGEIS). The proposed

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revised rule includes requirements for: blowout preventer use and testing plan; detailed mapping; enhanced

disclosure of chemical additives; and well pad siting setbacks. The chemical disclosure must identify each

chemical constituent intentionally added to the base fluid and its proposed concentration. The revisions also

establish a process for review of permit applications, including a 15 day public comment period, and provisions

for collection of fees. The proposed revised rules also contain detailed well construction, site preparation,

operational, and maintenance requirements.

These proposed revised regulations further the state’s legislative goals by ensuring that wells are

properly constructed and operated, while facilitating the state’s goal to provide for the efficient development,

production and utilization of natural resources of oil and gas in such a manner as to prevent injury to the

operator, mineral rights’ owners and the state as a whole.

With respect to the proposed rules related to SPDES, the ECL provides broad authority for the

protection of the waters of the State. Statutory authority is provided in ECL Sections 15-0103, 15-0105, 17-

0101, 17-0303, 17-0501 and 17-0511, 17-0807, 17-1709, and 71-1929 Specific authority for the proposed

regulations is found at ECL Sections 17-0101 and 17-0303, which declare it to be the public policy of the State

to maintain reasonable standards of water purity and authorizes the Department to prevent the pollution of the

waters of the State in accordance with water quality standards. Furthermore, ECL Section 17-0501 makes it

unlawful to discharge to any water of the State in violation of a water quality standard.

This proposed rulemaking updates Section 750-1.5 and add a new Part 750-3. The update to Section

750-1.5 conforms the regulation to the current federal process for issuance of Underground Injection Control

permits. Part 750-3 will prohibit certain HVHF activities and discharges and prevent the issuance of a SPDES

permit for such activities or discharges within specified distances from water resources. Specific changes have

been made in the proposed revised rules with respect to the prohibitions from intakes in flowing water intakes

and private water wells. Furthermore, Part 750-3 details the conditions that must be satisfied for the exemption

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for the requirement to obtain a SPDES permit for the injection of water, gas or other material through into a

well, except a disposal well, which facilitates the production of gas resources.

The proposed revised changes to Part 750-3 also specify the conditions under which an applicant may

receive a SPDES permit and a list of requirements applicable to HVHF operations. The proposed revised rule

also includes: a list of certifications required by the applicant; the need to develop a comprehensive stormwater

pollution prevention plan (SWPPP); the need to submit documentation of the anticipated depth of the top of the

objective formation, and the depth of the base of the known freshwater supply, along the proposed revised

length of the wellbore; best management practices for construction, reclamation and drilling related to HVHF

operations; requirements that all HVHF wastewater will be treated, recycled or otherwise disposed of;

monitoring, reporting and recording requirements; testing requirements for residential water wells; and a

groundwater monitoring program. The proposed revised rules also contain requirements regarding coverage

under a new HVHF General Permit.

Statutory authority for the proposed revised rules concerning state-owned lands is found in New York

State Constitution, Article XIV, and at ECL Sections 9-0105, 9-0301, 9-0501, 9-0507, 11-2101, 11-2103, and

45-0117. The Department has the responsibility to exercise care, custody and control of state-owned lands and

to make rules and regulations governing their use. The ECL also provides the Department with the authority to

receive and accept land for conservation, watershed protection, forest management and to conserve rare plants

and ecological communities on state-owned lands and lands under the jurisdiction of the Department. The

proposed revised regulation fulfills the legislative objectives by ensuring that the production of natural gas

using HVHF does not interfere with the purpose for which state-owned land was acquired.

Needs and Benefits. The proposed revised revisions to Parts 550 through 556 will update and improve

regulatory conditions in the state by ensuring that well operators obtain adequate financial security to cover the

cost of plugging deep wells, providing the regulated community with sufficient time to commence operations,

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and specifying requirements for properly plugging and abandoning a well. The new Parts 560 and 750-3 will

ensure the minimization of the potential environmental impacts to New York’s water resources, ecosystems,

and air quality, as well as the impacts of HVHF on communities where these wells are expected to be drilled.

These regulatory revisions will inform and serve the public and regulated community, supplement the

Department’s ability to monitor and enforce certain measures identified in the SGEIS, and will update some of

the Department’s regulations to reflect technological advances and current industry practice.

The regulations, by providing for a balanced use of both the surface environment and the natural gas in

the subsurface, promote a greater level of environmental protection than would be the case without the

regulations. Greater environmental protection includes minimizing the probability and risk to uncontaminated

aquifers and drinking water wells, streams and surface waters, and maintaining the passive use of natural

resources, amongst others. Additionally, as identified in the SGEIS, by approving the utilization of HVHF it is

expected that there will be extensive job creation.

Costs to Industry. The costs to the regulated community for the proposed revised regulations will

generally not differ from the potential costs that should be expected from the mitigation measures and permit

conditions identified in the SGEIS. Cost projections from the Independent Oil and Gas Association of New

York (IOGA) for complying with the 2011 revised SGEIS range from $400,000 to $1,700,000 for the first well

drilled on a well pad. The Department conducted a limited cost assessment, and found that, with respect to at

least two categories of cost estimates, IOGA’s estimates were excessive. The Department requested industry to

provide additional cost information, but the Department has not received any additional information. The use of

the general permit for stormwater management will reduce regulatory fees and other burdens below what would

be required if individual permits were issued. The prohibition of surface activities associated with HVHF on

state-owned lands might render some gas resources unavailable, which could result in potential lost opportunity

for industry and leaseholders. In addition, costs to such leaseholders could increase if they choose to acquire

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surface access outside state-owned lands.

State Costs. These regulations will create additional costs for several state agencies, including the

Departments of Environmental Conservation (Department), Health (DOH), Transportation (DOT), Public

Service and Agriculture and Markets. DOH would incur costs investigating complaints related to public health

concerns; DOT would be expected to review transportation plans that drillers submit with well applications;

Public Service staff would be involved in the siting and construction of natural gas transmission pipelines; and,

Agriculture and Markets would incur additional costs in its Agricultural District Program.

The actual costs that may be incurred by the Department and other state agencies cannot be currently

estimated, given a lack of necessary information. However, the implementation of these regulations can be

expected to require a significant increase from the existing Department staffing levels to carry out the large

number of activities relating to permits, with actual staffing levels dependent on the actual level of activity.

Local Government Mandates. While the proposed revised regulations do not mandate the expenditure

of funds by any sector of local government, local governments will likely incur some indirect effects as a result

of the Department’s approval to utilize HVHF. The rules would require well operators to test private residential

water wells within 1,000 feet of a well pad’s location, or 2,000 feet in some circumstances. County health

departments may need to respond to issues with these residential water wells that may arise as a result of

testing. Those costs will be compliance driven and cannot be quantified at this time.

These regulations would allow operators, under certain requirements, to dispose of flowback water and

production brine through publically owned treatment works (POTWs). To accept this water, POTWs must

perform a headworks analysis to ensure they can properly remove contaminants expected to be present in

flowback water and production brine prior to discharge.

In addition, heavy truck traffic will result in local costs for road maintenance, though the proposed

revised rules contain requirements to assist in mitigating those impacts. It is projected that HVHF activities

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would result in a substantial increase in economic activity in the affected areas and also result in a substantial

increase in tax revenues to the state and to localities. These revenues are expected to offset local government

costs that may result from HVHF activities.

Paperwork. The proposed revised rules include new paperwork requirements for all well operators,

including: the need to notify and receive approval to re-fracture a well; a requirement to submit an interim Well

Drilling and Completion Report; and new paperwork requirements specific to HVHF. The draft regulations

also require submissions to the Department pursuant to the stormwater general permit. Since the majority of

HVHF activities would be under a general permit using standardized forms, less paperwork will be generated

than required by an individual permit.

Duplication. This proposal is not intended to duplicate any other federal or State regulations or

statutes, as there is no federal regulatory program covering HVHF.

Alternatives. The Department examined the “no-action” alternative, in which mitigation measures and

other requirements resulting from the environmental review process would alone direct these operations.

However, the no-action alternative could create uncertainty for the regulated community and the public because

controls over HVHF activities would not be promulgated. The Department considered the denial of permits for

HVHF, but while this alternative would fully protect the environment from any environmental impacts

associated with HVHF, it would eliminate the economic benefits.

Federal Standards. There is no federal regulatory framework over HVHF, although in April 2012, EPA

finalized air emission standards for the entire oil and gas industry. There are no applicable Federal standards

for groundwater protection. Thus, the proposed revised rules exceed minimum federal government standards.

There are applicable Federal standards for stormwater and New York meets or exceeds all federal requirements.

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Compliance Schedule. The regulated community will be required to comply upon enactment of the

rules.