gas drilling guide - otsego county, new york

• • • Draft for review only. Please do not cite or quote.• • •

Gas Shale Rush:A Guide on the Legal Issues

Water and Land Use Law ClinicCornell University Law School

Ithaca, NY 14853March 2009

ForMunicipal Officials

andTechnical Providers


Review Comments for:Gas Shale Rush: A Guide on the Legal Issues

Note to Reviewers:• We intend to put more photographs, diagrams, etc., in the document, and solicit

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Contact:Mary Jane Porter607-272-9912 orEmail: [email protected]


Prepared by:Kaci White*

Joseph G. Tucci*Natalya S. Zelensky*

Keith S. PorterCornell Law School Water Law Clinic

Editing and ProductionMary Jane Porter

*Cornell Law School Water Law Clinic students, assisting the Upper SusquehannaCoalition (USC), a group of soil and water conservation district managers in southernNew York and Pennsylvania, in educating its members on the current and future laws thatgovern Marcellus Shale gas drilling. This draft guidance document is intended for publicofficials and technical providers and will continue to be shaped as the DEC develops itsMarcellus Shale regulatory scheme.

Potential Editorial/Advisory/Review Board

Jim Curatolo, Upper Susquehanna CoalitionMike Lovegreen, Bradford County, PA, Soil and Water Conservation District

Dean Frazier, Delaware County Action Plan (DCAP)Joseph Graney, SUNY, Binghamton

Jennifer Fais, Southern Tier Regional Planning BoardBrad Gil, Independent Oil & Gas Association of New York

Sponsored by:Upper Susquehanna CoalitionDelaware County Action Plan


Table of Contents

Acknowledgements

Executive Summary

List of Figures

List of Tables

Overview ........................................................................................1Marcellus Shale ........................................................................1Objectives and Goals ...............................................................1

Water Quantity, Quality and Sediment: Regulatory Concerns ..............2Introduction .............................................................................2

Regulatory Scheme .........................................................2Overview: Gas Permitting and Drilling ..............................3

Water Quantity .........................................................................5Recommendations ...........................................................7

Water Quality ...........................................................................7Recommendations ......................................................... 12

Sediment and Erosion ............................................................ 12Recommendations ......................................................... 15

State Environmental Quality Review Act (SEQR) ............................... 16Background............................................................................ 16Process and Factors............................................................... 16The DSGEIS ........................................................................... 19

Environmental Assessment ............................................ 20Recommendations ......................................................... 22

Landscape Issues .................................................................. 22Accomodation Doctrine ................................................. 23

Well Spacing and Citing.......................................................... 23


Pipelines ....................................................................................... 25Background .............................................................................. 25Regulations ............................................................................... 25

Ground Coverage, Location and Spacing ......................... 26Pollutants and Stormwater Discharges ............................ 27Safety and Maintenance .................................................. 27Technical DPS Regulatory Questions ............................... 28

Public Participation for Siting and Construction ........................ 31

Appendices:A: Gas Leases ........................................................................... 32B: Eminent Domain .................................................................... 39C: Conflict Resolution ................................................................ 42D: Guide to the Geohydrology of the Area ................................. 43E: Technical Resources ............................................................. 44F: Acronyms and Glossary......................................................... 45G: References ........................................................................... 47H: Best Management Practices for Gas Drilling ......................... 48

Table of Contents (cont.)


Overview

Marcellus ShaleThe Marcellus Shale is a black shale formation

that extends deep underground from southern NewYork into Pennsylvania, Ohio and West Virginia.“Although the Marcellus Shale is exposed at theground surface in some locations in the northernFinger Lakes area, it is as deep as 7,000 feet or morebelow the ground surface along the Pennsylvaniaborder in the Delaware River valley.” Gas drillingactivity in the Marcellus Shale is expected to beconcentrated in areas where the Shale is deeper than2,000 feet. http://www.dec.ny.gov/energy/46288.html.

The gas industry is interested in the MarcellusShale because of the natural gas it contains andbecause recent developments in technology have madegas exploration possible.“Geologists estimate thatthe entire MarcellusShale formation containsbetween 168 trillion to516 trillion cubic feet ofnatural gas throughoutits entire extent.” How-ever, it is not currentlyknown how much of thenatural gas can feasiblybe commercially recov-ered from the portion ofthe Marcellus in NewYork. The lightness anddepth of the Shalepreviously made explor-ing and extracting gas an

expensive proposition. However, recent enhancementsto horizontal drilling and hydraulic fracturing technol-ogy have made exploring gas in the Shale a viableoption. The gas industry’s interest has also increaseddue to “the proximity of high natural gas demandmarkets in New York, New Jersey and New Englandand the construction of the Millenium Pipelinethrough the Southern Tier.” http://www.dec.ny.gov/energy/46288.html.

Objectives and GoalsThis guide deals with broad concerns regarding

water quantity, water quality, sediment and erosion,and pipelines, as well as information about SEQR,New York State’s environmental quality review pro-cess. The guide has a particular focus on information

that will be helpful topublic officials andtechnical providers,including the Soil andWater ConservationDistrict staff. A goal ofthis study is to promoteprevention and mitiga-tion of damage to soiland water systemswherever possible, byencouraging coopera-tion between thegovernment, environ-mental professionals,and gas drilling compa-nies for their mutualbenefit.

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IntroductionThe legal and regulatory scheme surrounding

natural gas drilling in New York State is under trans-formation in an effort to address the unique concernsposed by widespread gas drilling proposed in theMarcellus Shale and other shale formations through-out the state. Gas production will primarily be accom-plished through the use of the slick water hydro-fracturing drilling technique, also called “hydrofracking,”which consumes and pollutes large amounts of freshwater.

To address these concerns, New York State’sDepartment of Environmental Conservation (DEC) iscurrently generating a new Supplemental GenericEnvironmental Impact Statement (SGEIS) regardingwater quantity, water quality, and other environmentalissues involved in the upcoming gas production thatthe DEC did not address in its original 1992 GenericEnvironmental Impact Statement on the Oil, Gas andSolution Mining Program (1992 GEIS). The DEC hasreleased its Final Scope for the Draft SGEIS.

The Final Scope is broad and encompasses a largenumber of potential environmental concerns related tonatural gas drilling and production in New York State.

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As a result, it is difficult to predict what the agencywill address with new regulations in its draft SGEIS,and what areas of concern it will leave to outdated ornonexistent regulations.

In the spring of 2009, the DEC will hold publichearings on its draft SGEIS. The DEC will also reviewwritten comments from the public in developing thedraft SGEIS. The public comment process is a crucialopportunity for soil and water conservation profession-als like Upper Susquehanna Coalition members to tellthe government why the DEC should implementvarious regulatory positions to protect the health ofNew York State’s soil, water, landscape, and citizens.

Regulatory Scheme

Q:What authority does the DEC havein relation to oil and gas in NewYork?

A: The New York State legislature has instructed theDEC to develop oil, gas, and mineral resources ina manner that will prevent waste, insure thegreatest economic recovery of oil and gas, andprotect the correlative rights of all owners and allpersons including the general public. 6 NYCRR550.1. As a result, the DEC has issued rules thatcorrespond with these responsibilities.

Water Quantity,Quality and Sediment:Regulatry Concerns


Q:Which division within the DEC isresponsible for regulating the oiland gas industry?

A: The DEC’s Bureau of Mineral Resources is respon-sible for administering and enforcing the DEC’srules relating to the exploration, drilling for,production, transportation, purchase, processingand storage of oil and gas in New York State. TheBureau of Mineral Resources is also responsiblefor preventing pollution from these oil and gasactivities. 6 NYCRR 550.2.

Q:How can DEC employees ensurecompliance with DEC regulations?

A: DEC employees are permitted “at all reasonabletimes” to enter and inspect property that is either“oil and gas property, tank farm, pump station,pipeline, refinery or underground storage project.”6 NYCRR 550.5.

Q:Have courts ever found environ-mental review by a state agencypreempted by federal law?

A: Yes. The following is an excerpt from McKinney’spractice digest showing one instance of federalpreemption.

Federal law preempted state regulation of naturalgas pipeline construction project, and thus publicutility did not improperly segment power purchaseagreement requiring construction and operation ofcombustion turbine generator by failing to includeconstruction of natural gas pipeline in its environ-mental review of project pursuant to State Envi-ronmental Quality Review Act (SEQRA), eventhough project and pipeline were part of integratedand cumulative development plan. McKinney’sECL § 8–0101 et seq.; 6 NYCRR 617.2. East EndProperty Co. No. 1, LLC v. Kessel, 46 A.D.3d 817,851 N.Y.S.2d 565 (2d Dep’t 2007), leave to appealdenied (N.Y. June 26, 2008).

Another instance of preemption has been found inthe following case:

National Fuel Gas Supply Corp. v. Public ServiceCom’n of State of N.Y.109 P.U.R.4th 383, 894 F.2d 571C.A.2 (N.Y.),1990.January 24, 1990 (Approx. 8 pages)

Congress placed authority regarding the locationof interstate pipelines-in the present case affectingcitizens of four states in addition to New York-inthe FERC, a federal body that can make choices inthe interests of energy consumers nationally, withintervention afforded as of right to relevant statecommissions. Because FERC has authority toconsider environmental issues, states may notengage in concurrent site-specific environmentalreview. Allowing all the sites and all the specificsto be regulated by agencies with only local con-stituencies would delay or prevent constructionthat has won approval after federal considerationof environmental factors and interstate need, withthe increased costs or lack of gas to be borne byutility consumers in other states.

Overview: Gas Permittingand Drilling Process

Q:How long does the initial DECpermitting process take?

A: Permitting time for an initial permit is nevercertain and approval of the permit by the DEC isnever guaranteed.

Q:How long will drilling take?A: Drilling usually takes two to four weeks, varying

with factors such as depth and time of year. Deepdrilling may require up to two months.

Q:What happens when drilling iscomplete?

A: Usually the land around the drilling site is re-claimed within 45 days. Vegetation will grow backwith time.

Q:How much area does a well platformoccupy?

A: Drilling areas range in size depending on thedepth of the well, from less than one acre to overtwo acres.

Q:What should landowners expect interms of equipment and disturbanceduring drilling?

A: Heavy equipment and the drilling rig will enter inand out of property during drilling. Gas companieswill build access to accommodate this equipmentand will clear trees and vegetation. Dust, noise,

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and exhaust fumes will occur during drilling.Wellhead assemblies, meters and tanks willremain on-site near the well location for the life ofthe well.

Q:Who are the parties in gas drilling?A: • Landmen

• Exploration companies• Sub-contractors• Regulators• Landowners

Q:How are drilling violationsremedied?

A: Article 23, Title 3 of the Environmental Conserva-tion Law (“ECL”) authorizes the DEC to requirethat wells be drilled, constructed, operated andplugged, and the surrounding land reclaimed, toprevent or remedy “the escape of oil, gas, brine orwater out of one stratum into another” and “thepollution of fresh water supplies by oil, gas, saltwater or other contaminants.” The statute alsogives the DEC authority to “order an immediatesuspension of drilling or production operationswhenever such operations are being carried on inviolation . . . “ ECL 23-0305(8)(d) and (g).

ECL Article 71, Title 13, grants the DEC broadauthority to address violations of Article 23 or anyregulation, order or permit condition. The statuteallows the DEC to impose administrative sanc-tions, including civil penalties of up to $5,000 fora violation or offense and up to $1,000 for eachday a violation continues. The DEC Commissioner

has the power to require the violator to reclaimand repair the affected site.” ECL 71-1307(1).

Article 71 also gives the New York AttorneyGeneral authority to impose civil sanctions andcriminal sanctions, with penalties or fines of up to$1,000 per day for continuing violations and up toone year imprisonment, or both. The DEC, actingthrough the Attorney General, may also seek courtinjunctions forbidding a violator from participatingin violations or threatened violations of Article 23.

Q:How are gas rights determined inNew York?

A: Gas accumulates in underground rock formationsknown as reservoirs. These reservoirs vary inshape and size and do not follow the artificialproperty line boundaries on the surface of theland. Because of this, the New York State Depart-ment of Environmental Conversation (“DEC”) setswell “spacing units” which may consist of one ormore properties. Land owners have rights in thegas underneath their property to the extent thatthis right has not been sold or otherwise givenaway. Owning the gas rights on property in aspacing unit entitles landowners to the opportu-nity (correlative right) to receive the benefits ofdrilling in that spacing unit. If landowners leasetheir land, their royalty payment under the leaseis based on a given landowner’s share of thespacing unit. If a well operator does not own all ofthe gas rights in the spacing unit, the DEC mustaddress this issue through the compulsoryintegration process.

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Water Quantity

Q: How much water will hydrofrackingconsume?

A: Estimates on water consumption vary, with watermeasured in the millions of gallons: anywherefrom 1 to 10 million gallons of water might beused for each fracking. So far, the DEC has notspecified the amounts of water it expects drillers touse for each fracture; in its Final Scope, theagency merely said that each well may require“millions of gallons” of water. Final Scope for draftSupplemental GEIS at 5, available at http://www.dec.ny.gov/docs/materials_minerals_pdf/finalscope.pdf.

Once water is used in a fracking, some water comesback up to the surface, and some water remains in therock formations. The water that does not resurface isconsidered to be permanently removed from itswatershed.

Q: Who regulates water withdrawals inNew York State?

A: The DEC regulates water withdrawals statewide byrequiring permits for use of water supply systems,including permits to enter into contracts for asupply of water. 6 NYCRR 601.3. Generally, localmunicipalities have existing permits for specifiedquantities of water; some municipalities that donot currently consume their maximum allottedquantity have entered into agreements to sell theexcess water to gas companies.

In the Susquehanna River Basin and the DelawareRiver Basin, two federal-state agencies—theSusquehanna River Basin Commission (SRBC)and Delaware River Basin Commission (DRBC),respectively—regulate water withdrawals.

SRBC recently changed its water withdrawalregulations, which are contained in 18 CFR Part806. Effective January 15, 2009, the changes:• Established a new Approval By Rule process,

similar to the existing rule in 18 CFR §806.22(e), to regulate all consumptive useactivity related to the development of theMarcellus and Utica Shales, not just consump-tive use by public water supply systems;

• Regulate natural gas well development projectson a drilling pad basis;

• Allow drilling operators to use a wide range ofwater for hydrofracking, including wastewatertreatment facility discharge, mine pool waterand other lesser quality waters, public watersupply sources, and other withdrawals sepa-rately approved by SRBC;

• Require metering, daily use monitoring andquarterly reporting, and compliance withSRBC’s consumptive use mitigation require-ments in order for water withdrawal applicationsto be approved;

• Require accounting for production fluids andbrines utilized for subsequent fractures. Thesefluids, however, are not included in the con-sumptive use calculation in order to incentivizere-use;

• Require projects to demonstrate compliance withstate and/or federal law for the treatment anddisposal of flow-back or produced fluids, includ-ing brines; and

• limit the new administrative approvals to a termof five years.

Final Scope at 26-27; SRBC Final Rulemaking forNatural Gas Well Development Projects (with linkto Federal Register pdf), available at http://www.srbc.net/programs/projreviewmarcellus.htm;specific section numbers within 18 CFR Part 806can be found in the Federal Register pdf and readin full text from http://www.law.cornell.edu/cfr/.

DRBC, like SRBC, has asserted jurisdiction overwater withdrawals for drilling in its watershed.Although DRBC has begun considering generalconcerns such as flow rates and water pollution, ithas not yet begun a rulemaking process forMarcellus Shale water withdrawals like SRBC has.Final Scope p28..

Q: Where will gas companies obtainwater?

A: The DEC predicts that gas companies will obtainwater from off-site surface freshwater bodies suchas rivers and streams as well as groundwatersupplies. Final Scope at 24.

Water quality standards established by stateregulations can be a check on where freshwaterbody withdrawals occur, because the standardsprohibit any alteration in flow that would impair afresh surface waterbody’s designated best use. 6NYCRR 703.2, available by searching Title 6Environmental Conservation from the “NYCRR”link at the top of the page at http://www.dos.state.ny.us/info/nycrr.htm.


Similarly, in the Susquehanna River Basin, SRBCregulations require many projects to show that aminimum flow in the freshwater body is main-tained in order to receive SRBC approval. Even if aproject with passby flow requirements has beenapproved, withdrawal must cease if the minimumflow is not maintained. Final Scope at 27. Asmentioned above, gas companies will likely obtainsome of this water from excess municipal watersupplies.

Q: How can gas drillers reduce waterconsumption?

A: Gas drillers can reduce the amount of fresh waterthat fracking operations consumer by using othertypes of water, including:• Flowback fluids that have resurfaced from

previous fracking;• Discharge from water treatment facilities; and• Briny water supplies.

SRBC’s new regulations incentivize gas companiesto reuse flowback fluids by allowing companies tonot count flowback fluids as consumptive wateruse. Companies must still account for the reusedfluids, but are not subject to the mitigationregulations that would apply if the fluids were notrecycled. SRBC Final Rulemaking for Natural Gas

Well Development Projects (with link to FederalRegister pdf), available at http://www.srbc.net/programs/projreviewmarcellus.htm.

The DEC is also considering the feasibility ofrequiring gas drillers to reuse fracturing flowbackfluid as a possible element of the upcomingSupplemental GEIS. Final Scope at 14-15.

Q: Will existing water needs beprotected in the event of a watershortage?

A: The DEC can deny or limit a permit for a watersupply contract if a water shortage threatensdrinking water supplies. 6 NYCRR 601.3

SRBC can deny water withdrawal applications orlimit approval if withdrawal would have significantadverse impacts to the Susquehanna River Basin.Possible impacts include lowering of groundwateror stream flow levels, affecting fish or wildlife, orcausing water quality degradation that may injureexisting or potential water uses. 18 CFR §806.4(a)(2)(iii), available at http://www.law,cornell.edu/cfr.

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Recommendations

The DEC should:• Require drilling companies to reuse fracturing

flowback fluids to reduce the quantity of freshwater pollution that results from the drillingprocess.

• Create incentives for drilling companies to useother non-potable water for fracturing opera-tions, such as discharge from water treatmentfacilities and briny water.

The DEC and SRBC should:• Closely monitor groundwater and stream flow

levels to ensure adequate drinking water sup-plies for the public.

• Hire adequate staff to ensure effective water levelmonitoring.

• Deny or limit water withdrawal permits for gasdrilling operations if public water supplies arethreatened.

DRBC should review its water withdrawal regula-tions with protection of adequate water supplies inmind.

Water QualityQ: What additives make up fracking

fluid?A: Fracking fluid includes water, a proppant such as

sand, and chemicals such as bactericides,surfectants, nitrogen, hydrochloric acid, and manyothers. Final scope at 9.

Q: What kind of access do agenciesand landowners have to frackingfluid formulas?

A: The DEC retains authority to request formulainformation from drilling companies. In its FinalScope, the DEC reports that it is collecting infor-mation on and developing a database for chemicalconstituents of additives that are combined withfresh water to create fracking fluid. Final Scope at10. The DEC also reports that: “The chemicalmanufacturing companies and theserviccompanies that perform the fracturing aresubmitting chemical composition information onthe different additives that may be proposed foruse in fracturing shale formations in New YorkState.” In addition, the DEC will not issue a wellpermit to operators until the agency has “completechemical composition information for all of theproposed additives.” Final Scope at 11. New YorkState Public Officer’s Law and the DEC’s RecordsAccess Regulations govern the handling of tradesecret information submitted to DEC.

Bactericides, which are among fracking fluidadditives, must be registered for use in New Yorkaccording to ECL § 33-0701. Bactericides mustalso be properly labeled and the labels must bekept on-site during application and storage. FinalScope at 10.

In addition to the DEC controls listed above, theDEC will consider the following issues in develop-ing the draft SGEIS:


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• Chemical composition of fracturing fluid additivesproposed for fracturing shale formations in NewYork. This information will be shared with otherDivisions within DEC, including the Division ofWater (DOW), as well as with the New York StateDepartment of Health and will be reviewed todetermine if applicable standards and regula-tions are sufficient to prevent or mitigate poten-tial impacts of their use and management.

• The feasibility of requiring use of green or non-chemical fracturing technologies and additives.

• Hydraulic fracturing design and modeling, withemphasis on containment of fractures andfracturing fluid in the target formation.

• The effectiveness of the regulations of other oiland gas producing states with high volumehydraulic fracturing of shale and other low-permeability reservoirs.

Final Scope at 11-12.

Some gas companies claim that fracking fluidformulas are trade secrets and are exempted fromthe Freedom of Information Law (FOIL) underPublic Officers Law § 87(2)(d), which exemptspublic disclosure of trade secret information ifdisclosure would cause substantial injury to thecompetitive position of the company. In a June2008 decision by the New York Court of Appeals,the state’s highest court increased the burden oncompanies that claim that information should beexempted from disclosure because it is a tradesecret. In the case, the Court of Appeals changedprior law to require more proof that an informationdisclosure would substantially injure a company’scompetitive advantage. The court stated, “To meetits burden, the party seeking exemption mustpresent specific, persuasive evidence that disclo-sure will cause it to suffer a competitive injury; itcannot merely rest on a speculative conclusionthat disclosure might potentially cause harm.”Markowitz v. Serio, 11 N.Y.3rd 43 (2008).

Q: Where can operators drill wells?A: Operators’ ability to drill wells in a given location

depends on whether the DEC considers drilling onthat type of location to have a significant environ-mental impact. The DEC reviewed the impact of oiland gas drilling on several types of locations, andits findings are contained in the 1992 Final GEISon the Oil, Gas and Solution Mining Program(“1992 GEIS”), available at http://www.dec.ny.gov/energy/45912.html. Thesefindings are summarized below, according tolocation type.

Any location, when no other permits are required:no significant impact.In the 1992 GEIS, the DEC found that issuing astandard, individual oil or gas well drilling permitanywhere in the state, when no other permits areinvolved, does not have a significant environmen-tal impact.Final Scope at 4.

Location above an aquifer: no significant impact.The DEC found that issuing an oil and gas drillingpermit for locations above aquifers does not have asignificant environmental impact because ofspecial regulations for freshwater aquifer drillingthat the DEC has already implemented. See 1992GEIS, Chapters 8 and 9, available at http://www.dec.ny.gov/energy/45912.html; see alsoFinal Scope at 4, available at http://www.dec.ny.gov/docs/materials_minerals_pdf/finalscope.pdf.

Location in a State Parkland or Agricultural District:possible significant impact.The DEC found that issuance of a drilling permitfor a location in a State Parkland or in an Agricul-tural District may be significant and requiress asite-specific SEQRA determination. (Final Scopefor dSGEIS, p4)

Location between 1,000 to 2,000 feet from amunicipal water supply well: possible significantimpact.The DEC found that issuance of a drilling permitfor a location between 1,000 to 2,000 feet from amunicipal water supply well may be significantand requires a site-specific SEQRA determination.Final Scope at 4.

Location less than 1,000 feet from a municipalwater supply well: always significant impact.The DEC found that issuing a drilling permit forlocations less than 1,000 feet from a municipalwater supply well is always significant and re-quires a site-specific SEIS addressing groundwaterhydrology, potential impacts, and mitigationmeasures. Final Scope at 4.

Location that requires other DEC permits: possiblesignificant impact.The DEC found that issuing a drilling permit for alocation that requires other DEC permits may besignificant and requires a site-specific SEQRAdetermination. Final Scope at 4.


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Other locations not addressed in 1992 GEIS: underconsideration for draft SGEIS.Some geographic areas, espcecially the easternthird of New York State, were not viable locationsfor oil and gas activity when the DEC developedthe 1992 GEIS. The DEC is now considering theselocations to determine whether additional drillingregulations are needed in light of the high-volumehydraulic fracturing that may take place. FinalScope at 4-6.

Locations under consideration for additionalregulations include:• Proposed water sources within the

Susquehanna River, Delaware River or GreatLakes-St. Lawrence River Basins;

• Proposed water sources outside theSusquehanna River, Delaware River or GreatLakes-St. Lawrence River Basins;

• New York City Watershed, including those inproximity to subsurface watershed infrastructure;

• Catskill Park; and• Upper Delaware River corridor.

Q: What kind of groundwaterprotections are already in place forgas drilling?

A: Well casing and cementing:Regulations regarding well casing already existand will continue to be in place. The DEC’s wellcasing and cementing practices require drillers toimplement various technical precautions to isolatea drilling operation from groundwater. For ex-ample, freshwater aquifers must be sealed behindcemented steel pipe before any fluid can bereleased into the bore, and surface casing mustextend at least seventy-five feet beyond thedeepest freshwater zone or seventy-five feet intobedrock.

Well plugging:Standards for well plugging also already exist aspart of New York’s oil and gas regulations and arecrucial to the continued safety of water supplies inthe decades after a well has been depleted orabandoned. In the Final Scope, the DEC describeswell plugging standards:

“Unsuccessful wells and wells whose produc-tive life is over must be properly plugged andabandoned, in accordance with Department-issued plugging permits and under the oversightof Department field inspectors. Proper plugging iscritical for the continued protection of groundwa-

ter, surface water bodies and soil. Financialsecurity to ensure funds for well plugging isrequired before the permit to drill is issued, andmust be maintained for the life of the well.

When a well is plugged, downhole equipment anduncemented pipe must be removed from thewellbore, and cement must be placed acrosscritical intervals to ensure seals between hydro-carbon and water-bearing zones. These downholecement plugs supplement the cement seal thatalready exists at least behind the surface (fresh-water protection) casing and above the completionzone behind production casing. Most wells drilledin primary and principal aquifers will have beencemented to surface behind each casing string.

Intervals between plugs must be filled with aheavy mud or other approved fluid. For gas wells,in addition to the downhole cement plugs, aminimum of 50 feet of cement must be placed inthe top of the wellbore to prevent any release orescape of hydrocarbons or brine from the wellbore.This plug also serves to prevent wellbore accessfrom the surface, eliminating it as a safety hazardor disposal site.” Final Scope at 17; see also 1992GEIS, Chapter 11.

Q: What kind of surface waterprotections are already in place forgas drilling?

A: Surface water protections are extremely importantin gas drilling, primarily once fluid has flowedback as the mixed fracking fluid. Before fractur-ing, fresh water, sand and chemical additives aredelivered separately to the well site, according toDepartment of Transportation regulations.Fracking fluid is blended once it is pumped intothe cased and cemented wellbore, so there is nolong-term on-site storage of pre-mixed fracturingfluid. Final Scope at 12.

Storage is key in protecting surface water qualityfrom pollution by flowback fluids. New Yorkcurrently allows gas companies to use surfaceevaporation pits, which must be lined and re-claimed with forty-five days after drilling opera-tions have stopped. Cases of extreme pollutioncaused by evaporation pits have occurred inwestern states, underscoring the importance ofwise handling of flowback fluids. One option toprevent potential flowback pollution is to requiregas companies to use steel tanks to store flowback


fluids instead of evaporation pits. In developingthe draft SGEIS, the DEC plans to review whetheror not it will require well operators to use steeltanks to store fracking flowback fluids. FinalScope at 12.

Q: How will NORMs affect waterquality?

A: Some shales like the Marcellus Shale containNaturally Occurring Radioactive Materials(NORMs), which may come to the surface withflowback fluids. Gas companies and environmen-talists disagree on the extent to which NORMs willsurface with flowback fluids and whether they willsurface in large enough quantities to pose a threatto human health and the environment. If NORMssurface in large enough quantities, the issue offinding treatment facilities that can handle theNORMs will be very important.

The DEC plans to review issues concerningNORMs in its upcoming Supplemental GEIS; theDivision of Mineral Resources, along with theDEC’s Division of Solid and Hazardous Materials,has begun to collect data to determine whetherNORMs are a concern in Marcellus and othershale gas drilling. Analysis methods the Divisionsare using include field surveys and sample sur-veys using gamma ray spectroscopy, and theDivisions are examining new water and cuttingsamples as well as old samples from previouswells. Final Scope at 19. In 1999, the DEC foundthat for other rock formations in New York,concentrations of NORMs on gas and oil equip-ment and production wastes were not high enoughto pose a threat to public health or the environ-ment. Final Scope at 19; see also http://www.dec.ny.gov/chemical/23473.html.

Q: How is fracking fluid disposed?A: Each DEC well permit requires fluids to be re-

moved from the well site by a hauler with a Part364 Waste Transporter Permit. 6 NYCRR Part 364.Part 364 details requirements associated with thepermit, such as identifying the type of wastetransported, including any testing that may benecessary to determine whether or not the waste ishazardous, and ensuring that the waste is deliv-ered to an authorized waste receiving facility thatcan treat the waste.

Under current New York law, used fracking fluidis considered an industrial waste product, not ahazardous waste product. Classification of usedfracking fluid as a hazardous waste producewould impose more stringent waste requirementson gas companies than the DEC currently re-quires.

According to the DEC, potential disposal sites forused fracking fluid include:• Injection wells• Out-of-state industrial treatment plants• Municipal sewage treatment facilities• Other options

Injection wells:Injection wells are regulated under the DEC StatePollutant Discharge Elimination System(“SPDES”), and the federal Underground InjectionControl (“UIC”) program, which exist to protect thesafety of drinking water. More information on thepotential use of injection wells as disposal sitesfor used fracking fluid is in the question below.

Municipal sewage treatment facilities:Municipal sewage treatment facilities, also knownas Publicly Owned Treatment Works (POTWs), areregulated by the DEC’s Division of Water Re-sources (DOW). Final Scope at 13. The DECexplains that “DOW notified POTW operators in aDecember 8, 2008 letter that they may not accepthydraulic fracturing wastewater or producedfluids from gas well development unless they havean approved pre-treatment or mini-pretreatmentprogram, and an approved headworks analysis forthese fluids.” Final Scope at 14.

The DEC continues:“Any headworks analysis will require specificinformation regarding the fluids, includingchemical makeup data, with specific attentionpaid to the concentration of total dissolved solidsand aquatic toxicity data. Representative fluidsamples will need to undergo laboratory testing tosupport a POTW’s headworks analysis, and suchtesting must be conducted by a laboratorycertified by the New York State Department ofHealth (NYSDOH) Environmental LaboratoryApproval Program (ELAP).

The Division of Mineral Resources has beenproviding, and will continue to provide, DOW withall information pertaining to the chemical compo-sition of the hydraulic fracturing additives in an

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effort to assist in the review of any headworksanalysis received. The DOW will review theheadworks analysis and determine whether thePOTW has adequately evaluated the effects ofthe proposed discharge on POTW operation,sludge disposal, effluent quality and POTWhealth and safety; whether the discharge willresult in the discharge of a substance that willbe subject to effluent limits, action levels, ormonitoring requirements in the facility’s SPDESpermit; and whether the proposed dischargecontains any Bioaccumulative Chemicals ofConcern or persistent toxic substances thatmay be subject to SPDES effluent limits orother Department permit requirements orcontrols. If necessary after the review of theheadworks analysis, the Division of Water willmodify a POTW’s SPDES permit so that thetreatment operations are protected and dis-charge effluent limits and water quality stan-dards are met in accordance with 6 NYCRR§750-1.18 (4).21 Such a modification would besubject to public review.”

Final Scope at 14. An overview of POTWs andheadworks analyses is available at http://www.dec.ny.gov/chemical/8728.html.

The upcoming draft SGEIS will include a reviewby the DEC of the suitability of fracking fluiddisposal at permitted municipal wastewatertreatment facilities. Final Scope at 15. The DECwill also consider whether potential well permit-ting procedures, such as verification of a welldisposal permit or a conract with a specifictreatment plant in order to ensure that availabletreatment capacity exists to meet disposalneeds. Final Scope at 15. An example of theimportance of early, well-planned solutions forfracking fluid disposal is Pennsylvania, wherepollution problems have resulted from insuffi-cient treatment facilities for flowback fluids. Forexample, in October, Pennsylvania’s Departmentof Environmental Protection effectively issued amoratorium on local wastewater facilities fromaccepting flowback fluids for treatment becauseof severe pollution that had occurred.

Other optionsOther options for fracking fluid disposal that theDEC is considering include:• Reuse/recycling at other wells;• Disposal at existing or new private in-state

wastewater treatment facilities;• Injection for enhanced recovery in oil fields.

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Q: Will road-spreading be allowed as adisposal method for used frackingfluids?

A: No. The DEC has notified Part 264 haulers thatthey may not dispose fracking fluid by using it forroad-spreading: “Road spreading for dust controland deicing (by a Part 364 Transporter with localgovernment approval) is also discussed in theGEIS as a general disposition method used in NewYork for well-related fluids. In January 2009, theDivision of Solid and Hazardous Materials(DSHM), responsible for oversight of the Part 364program, released a notification to haulers apply-ing for, modifying, or renewing their Part 364permit that fracturing fluids obtained duringflowback operations may not be spread on roadsand must be disposed of at facilities authorized bythe Department or transported for use or re-use atother gas or oil wells where acceptable to theDivision of Mineral Resources. This notice speci-fies that only production brines may be used inroad spreading and that any entity applying for aPart 364 permit or permit modification to useproduction fluid for road spreading must submit apetition for a beneficial use determination (“BUD”)to the Department. The BUD and Part 364 permitmust be issued by the Department prior to anyproduction brine being removed from a well site.”Final Scope at 14.

Q: Is hydrofracking exempt from theSafe Drinking Water Act?

A: Section 322 of the Federal Energy Policy Act of2005 (2005 Energy Act) amended the Safe Drink-ing Water Act (SDWA) to exempt hydraulic fractur-ing from the definition of underground injection.2005 Energy Act § 322, available at http://www.doi.gov/iepa/EnergyPolicyActof2005.pdf.What this means is that hydrofracking is ex-empted from regulation under the federal Under-ground Injection Control program (UIC), whichrequires federal permits for injection of substancesthat could harm drinking water supplies. Thisexemption applies to the act of hydrofracking thatoccurs in the drilling process, when an under-ground rock formation is fractured to allownatural gas extraction. Section 322 did notexclude underground storage of flowback frackingfluid in underground formations; undergroundstorage of used fracking fluid is still subject tofederal UIC regulatory controls. Neither the EPAnor the DEC issues a permit for undergroundstorage of used fracking fluid without a demon-


stration that the fluid will not contaminate freshwater aquifers. Final Scope at 13.

An additional protection against aquifer pollutionfrom underground storage of fracking fluid is aDEC requirement that a well permit from theDivision of Mineral Resources be issued in order todrill or convert a well deeper than 500 feet forbrine disposal. Such a permit may not be issueduntil UIC and SPDES permits are obtained. TheDEC’s 1992 Findings Statement describes thepermitting process for brine disposal wells asrequiring an “extensive surface and sub-surfaceevaluation which is in effect a supplemental EISaddressing technical issues.” Additionally, a site-specific environmental assessment and SEQRdetermination are required for the permit. FinalScope at 13.

Q:What regulations exist to ensuredrilling companies properly closeand plug drill sites once productionceases?

A: The DEC has very specific provisions that must bemet to ensure that gas companies properly closeand plug wells, which is essential to the long-termprotection of water quality and surface environ-mental quality of the site. Part of the pluggingprovisions are contained in 6 NYCRR 555.5, whichdetails plugging methods, procedures, and re-ports.

Additionally, gas companies must provide finan-cial security for well plugging and drill site closureand leave it in escrow. 6 NYCRR 551.5. Thisfinancial obligation ensures that if a gas companyno longer exists or is unable to pay for a wellplugging when the time comes.

Recommendations

To protect water quality during gas production inNew York State, the DEC should :

• Facilitate water quality testing before, during, andafter drilling operations.

• Enforce current well casing and fluid handlingregulations.

• Ban the use of surface evaporation pits.• Require gas companies to use steel tanks to store

flowback fluids.• Define fracking flowback fluids as hazardous

waste rather than industrial waste.• Release fracking fluid formulas to, at a minimum,

property owners and tenants with land adjacent toor including a well site, and emergency personnel..

Sediment and Erosion

Q: What effect will gathering lineshave on sediment and erosion?

A: Gathering lines will have an enormous impact onthe landscape and soil conditions in New YorkState because of the large number of lines that willbe constructed in the near future. Gathering linesare small, low-pressure pipelines that transportgas from a production site to a processing loca-tion, and extensive networks of gathering lines willsoon cross the landscape.

Although gathering line construction has thepotential to cause sediment and erosion problems,these problems can be avoided or mitigated withgood planning and the assistance of soil and waterconservation districts. Early cooperation betweengas companies and soil and water specialists willbe the most efficient, cost-effective way to preventfuture hydrological problems across the state.

Q: Who regulates gathering lines?A: The New York Public Service Commission is the

primary government body that regulates gatheringlines. The DEC does not regulate gathering lines,except when gathering line construction woulddisturb an environmentally sensitive area such asa stream or a wetland. If gathering line construc-tion would disturb an environmentally sensitivearea, a DEC permit is mandatory under NewYork’s State Environmental Quality Review Act.Final Scope at 8.

The Public Service Commission has an environ-mental review and siting process for gatheringlines, and gives notice of potential gathering lineconstruction to the municipality where lines willbe built. People from that municipality, as well asother concerned individuals, may comment ongathering line siting. More information on thismay be found in this document’s section on PublicParticipation in Pipeline Siting and Construction .

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Q: What role could soil and waterconservation professionals have inthe gathering line siting andconstruction process?

A: Soil and water conservation professionals can helpensure intelligent, preventive gathering line con-struction by using the current regulatory system toparticipate in the Public Service Commission’spublic siting process, as mentioned above and indetail in this document’s section on Public Partici-pation in Pipeline Siting and Construction.

Another way that soil and water conservationprofessionals could help guarantee smartergathering line construction could be to change thecurrent regulatory structure so that the DECdirectly oversees environmental review of gatheringline siting in addition to the Public Service Com-mission. Soil and water conservation professionalscould argue that gathering line constructionshould presumptively be considered a disturbanceto environmentally sensitive areas because of thescale of the upcoming gas production in New YorkState. Professionals could argue that given thislarge scale, gathering lines should be viewed in theaggregate when determining their environmentalimpact. This argument could be made in the publiccomment periods in 2009 as part of the DEC’sreview process to create a Supplemental GEIS. Ifthis argument succeeded, gathering lines would besubject to the DEC’s regulatory system, which isperhaps more familiar to professionals than thePublic Service Commission’s environmental reviewmethods are. However, by using the Public ServiceCommission’s existing comment process, conserva-tion professionals might be able to work moreclosely with companies building gathering lines.This could potentially give soil and water conserva-tion professionals flexibility in finding creativesolutions to sediment and erosion challengesposed by gathering line construction.

It is worth noting that the Public ServiceCommission’s and the DEC’s environmental reviewprocesses are very similar in content. By encourag-ing the DEC to view gathering lines as warrantingDEC review as well, however, the chances ofnegative environmental impacts from line sitingcould decrease.

In its draft SGEIS, the DEC will describe theenvironmental review process and identify poten-tial measures to prevent or minimize adverse

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impacts from pipeline construction. Final Scope at8. Soil and water conservation professionals havespecialized knowledge about specific measures arebest to mitigate erosion problems arising frompipeline construction. As a result, a developmentof best management practices (BMPs) for gatheringlines would benefit both conservation profession-als and the gas industry alike. USC membersshould consider outlining BMPs for gathering lineconstruction and siting and submitting them tothe DEC during the public comment period thisspring.

Q: What are some existing sedimentand erosion controls that apply tothe gas industry?

A: One example of existing sediment and erosioncontrols is the DEC’s Stream Disturbance Permit.A Stream Disturbance Permit is required by theDEC for any well site activity that disturbs the bedor banks of a protected stream. Additionally, DECArticle 15 permits may be required to constructwater withdrawal infrastructure such as standpipes. These regulations may be relevant for gascompanies withdrawing water directly fromsurface bodies, rather than trucking water to thewell site for hydrofracking.

Under DEC regulations, a gas company’s failure toadhere to an erosion and sedimentation controlplan is a violation and may result in the DECimposing fines or penalties or immediately sus-pending drilling operations. One concern here isthat, although the DEC has power to penalize gascompanies for violations of erosion and sedimenta-tion control plans, the DEC does not currentlyhave the staff or resources to realistically monitorthe number of drilling operations that will begin inthe near future. Here, as in some other areas ofgas drilling regulation, regulations may already bein place but enforcement efforts will likely beinadequate. Soil and water conservation profes-sionals should encourage the DEC that an invest-ment in enforcement staff is necessary to preventfuture widespread sediment and erosion problemsthat could result from unchecked violations by gascompanies. Examples of the future monetary coststhat would be required to repair erosion andsediment problems caused by unenforced viola-tions would be especially helpful in arguing thisneed to the DEC


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Q: Did the Energy Policy Act of 2005exempt gas companies from theClean Water Act?

A: The Clean Water Act requires operators of smallconstruction sites to obtain National PollutantDischarge Elimination System (NPDES)stormwater permits for sediment runoff. Section323 of the federal Energy Policy Act of 2005 (2005Energy Act), however, exempts oil and gas well siteactivities that disturb between one and five acresfrom this requirement, whether or not the well siteactivities can be considered to be constructionactivities. Section 323 of the 2005 Energy Act iscodified at 33 U.S.C. § 1362(24), available athttp://www.law.cornell.edu/uscode/33/1362.html. The full text of the 2005 Energy Act isavailable at http://www.doi.gov/iepa/EnergyPolicyActof2005.pdf.

On May 23, 2008, U.S. Court of Appeals for theNinth Circuit held that the rule that the EPAissued in response to section 323 of the 2005Energy Act was unlawful under section 402(I)(2) ofthe Clean Water Act. Natural Resources DefenseCounsel v. EPA, 526 F.3d 591, 594 (9th Cir. 2008),available at http://www.ca9.uscourts.gov/datastore/opinions/2008/05/22/0673217.pdf; §402(l)(2) of the Clean Water Act codified at 33U.S.C. § 1342(l)(2), available at http://www.law.cornell.edu/uscode/33/1342.html. As aresult, the EPA must rewrite its regulation corre-sponding with the section 323 stormwater permitexemption.

Regardless of federal exemptions, the DEC hasauthority to require appropriate erosion andsedimentation controls at all well sites, regardlessof size. Final Scope at 34. The loss of a stormwaterpermit requirement on a federal level, however,means that New York State will be the sole en-forcer and the only source of remedies in case of aviolation. Federal requirements can be much morepowerful in terms of enforcement and legal rem-edies than state requirements; this loss places soleregulatory responsibility on an already-stressedstate environmental agency, which may have lessof an incentive to require and enforce sedimentand erosion controls without federal law leadingthe way.

Q: What power do local municipalitieshave to enforce sediment anderosion controls for gas drillingoperations?

A: Under existing New York law, local municipalitiesdo not have authority to manage gas drillingoperations except for jurisdiction over local roadsand real property taxes. ECL § 23-0303(2).

Although local municipalities have very little powerto dictate gas drilling operations, their power tocontrol gas companies’ use of local roads isimportant. This power of municipalities to regulatelocal roads is quite broad under Title 8 of NewYork State’s Vehicle and Traffice Law. Final Scopeat 38. Gas companies will use local roads exten-sively, both for heavy drilling equipment and fornumerous, around-the-clock truckloads of watercoming from and going to well sites. Conservationprofessionals should encourage municipalities toutilize this authority over local roads to retainsome benefit for the community; at the very least,communities could require gas companies to payfor repairs to the roads that they will inevitablywear down.

In the draft SGEIS, the DEC will review potentialmitigation measures to lessen the impact of theheavy road use that drilling will impose, including:• Route selection to maximize efficiency and public

safety;• Coordination with local emergency management

agencies and highway departments;• Upgrades and improvements to roads that will be

traveled frequently for water transport to and frommany different well sites;

• Use of rail or temporary pipelines where feasibleto move water to and from well sites.

Final Scope at 38.


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Recommendations

• The DEC should consider gathering lines aspresumptively having a significant impact ona sensitive environmental area because of theaggregate impact that gathering lines willhave on the soil and hydrology of theMarcellus Shale region.

• Soil and water conservation professionalsshould utilize the existing process for public

participation in the Public Service Commission’spermitting process for gathering line siting toencourage wise placement of lines.

• Local municipalities should use their power overlocal roads to tax gas companies or otherwiserequire them to repair the wear that they will imposeon the roads.


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BackgroundSEQR is the law that determines whether gas

companies will have to issue an environmental impactstatement before obtaining a permit from the DEC.Environmental impact statements will help us deter-mine what the impacts of drilling will be on thelandscape. Thus, by understanding the SEQR process,we will be able to determine whether gas companieswill have to issue environmental impact statements.

Under New York state law, actions that will havean impact on the landscape need to comply with theSEQR, which requires certain activities to complete theSEQR review process before they are approved by theDEC.

SEQR Process and FactorsThe SEQR process evaluates the environmental

impact of certain activities on the land. Natural gasdrilling is likely to have many effects on the landscape.Thus, it must undergo the SEQR process undercertain circumstances. However, the regulationsrequiring SEQR evaluations for natural gas drilling arenot expansive enough – they exclude most pipelinedrilling, which is what we will see the most inMarcellus Shale. It is important to urge the DEC toadopt more extensive SEQR regulations that willrequire this type of drilling activity to undergo anenvironmental impact process before it is approved byhaving to issue an environmental impact statement(EIS).

Most activities or projects that are proposed by aunit of local government or state agency and allpermits from a New York state agency are required toundergo an environmental impact statement under 6NYCRR Part 617 State Environmental Quality Review(SEQR). “SEQR requires the sponsoring or approvinggovernmental body to identify and mitigate the signifi-cant environmental impacts of the activity it is propos-ing or permitting.” http://www.dec.ny.gov/public/357.html. Based on this requirement, DEC would haveto identify and mitigate significant environmental

State EnvironmentalQuality Review Act

(SEQR)

impacts of the gas drilling that it would be issuingpermits for in the Marcellus Shale.

Section 617.1(c) of SEQR states that all agenciesare required to “determine whether the actions theydirectly undertake, fund or approve may have asignificant impact on the environment, and, if it isdetermined that the action may have a significantadverse impact, prepare or request an environmentalimpact statement.” Based on this statutory language,it is quite clear that gas drilling companies will only berequired to issue an EIS if the DEC determines thatdrilling will have a significant adverse impact. If theDEC makes this finding, then the companies will haveto prepare an EIS. However, if the DEC feels that thedrilling will not have a significant adverse impact onthe environment, then the companies will not have toissue an EIS. The current regulations in place at theDEC are not inclusive enough as to what types ofnatural gas drilling will have a significant adverseimpact on the environment

SEQR lists several factors that an agency mustexamine to determine whether a proposed activity mayhave a significant adverse impact on the environmentin § 617.7. Thus, the agencies in New York state arenot left to determine what kinds of actions may havean adverse impact on the environment in an ad hocmanner. The numerous criteria that SEQR lists arelocated in § 617.7(c).

Activities are defined under SEQR as either Type I,Type II or Unlisted. Type II actions do not require anEIS, determination of significance or findings state-ments. § 617.3(f) SEQR. Section 617.4 of SEQR listsseveral actions that fall under the category of TypeI,which are then more likely to require an EIS filingthan Unlisted actions. Section 617.4’s Type I list is notexclusive – other proposed activities may be identifiedby an agency as having the potential to have a signifi-cant adverse impact on the environment and requirean EIS. § 617.4(a)(1). However, the fact that an actionor project has been listed as a Type I action carrieswith it the presumption that it is likely to have asignificant adverse impact on the environment andmay require an EIS. § 617.4(a)(1).


For all individual acts that are identified as eitherUnlisted or Type I, the agency determining significancemust “compar[e] the impacts which may be reasonablyexpected to result from the proposed action with thecriteria listed in subdivision 617.7(c) of this Part[SEQR].” § 617.4(a)(1). Some, natural gas drillingcompanies will likely seek large areas of land to leasefrom the state in order to pursue natural gas drillingin the Marcellus Shale. According to § 617.4(b)(4),“the acquisition, sale, lease, annexation or othertransfer of 100 or more contiguous acres of land by astate or local agency” is a Type I action. This identifi-cation should greatly increase the chance that gascompanies’ efforts to lease large tracts of land from thegovernment will require them to issue an EIS. Ifnatural gas drilling will require the physical alterationof 10 acres or more then it is identified as a Type Iaction under § 617.4(b)(6)(i). These types of definitionsmake it seem more encouraging that natural gasdrilling will fall under the scope of SEQR and berequired to issue environmental impact statements.Another activity that natural gas drilling may involveand thus fall under a Type I action are actions “thatwould use ground or surface water in excess of2,000,000 gallons per day.” § 617.4(b)(6)(ii).

Q: What is SEQR?A: The State Environmental Quality Review Act

(SEQR) is a New York state law that requires thesponsoring or approving governmental body toidentify and mitigate the significant environmentalimpacts of the activity it is proposing or permit-ting.

Q: How is SEQR enforced? Whathappens if agencies don’t complywith SEQR?

A: SEQR is self-enforcing. Thus, every governmentagency is responsible to see that it meets its ownobligations to comply with the law. In theMarcellus Shale context, the DEC is charged withissuing regulations regarding the SEQR process,but has no authority to review the implementationof SEQR by other agencies.

Since there is no SEQR police, if an agency doesnot comply with SEQR, citizens or groups who candemonstrate that they may be harmed by thisfailure may take legal action against the agency.Project approvals may be rescinded by a court anda new review required under SEQR.

Q: What are the steps in the SEQRprocess? What actions does SEQRrequire an agency to take?

A: Step 1: Classify the Action• The first step in classifying the action is to

decide whether it is subject to SEQR.- An action is subject to review under SEQR if

any state or local agency has authority toissue a discretionary permit, license or othertype of approval for that action.

- SEQR also applies if an agency funds ordirectly undertakes a project, or adopts aresource management plan, rule or policy thataffects the environment.

- If the proposed action does not require adiscretionary decision, there is no requirementfor review under SEQR.

• The second step in classifying an action is todetermine whether it is a Type II Action, a Type IAction or an Unlisted Action.- Type II actions do not require an EIS, determi-

nation of significance or findings statements (§617.3(f) SEQR).

- Section 617.4 of SEQR lists several actionsthat fall under the category of Type I, whichare then more likely to require an EIS filingthan Unlisted actions.

- Section 617.4’s Type I list is not exclusive –other proposed activities may be identified byan agency as having the potential to have asignificant adverse impact on the environmentand require an EIS (617.4(a)(1)). However, thefact that an action or project has been listedas a Type I action carries with it the presump-tion that it is likely to have a significantadverse impact on the environment and mayrequire an EIS. (617.4(a)(1)).

Step 2: Complete the EnvironmentalAssessment Form (EAF)• Type I Actions:

- Required to complete a full EAF- Requirement may be waived if a draft EIS is

prepared and submitted with the application• Unlisted Actions:

- Do not always require preparation of a fullEAF.

- Agency may require a full EAF if the short EAFwill not provide sufficient information, or itmay waive the requirement for an EAF if adraft EIS is prepared and submitted with theapplication.

- If the option to prepare a full EAF is notexercised, a short EAF must be completed.

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Step 3: Coordinated Review• Type I Actions: Coordinated review is required

for all Type I Actions.- The involved agency initially receiving an

application for approval circulates thecompleted Part 1 of the full EAF and anyother information supplied by the applicantto the other involved agencies.

• Unlisted Actions: Have coordinated / uncoor-dinated / conditioned negative declarationreview options.- If any involved agency decides to coordinate

the review, or intends to require a draft EIS,that agency must contact the other involvedagencies informing them of the decision tocoordinate.

- Uncoordinated Review: Each involvedagency acts as a lead agency, and indepen-dently conducts an environmental reviewand determines the significance of theaction. If all involved agencies issue negativedeclarations, the project may go forward. Ifany of the involved agencies issues apositive declaration, requiring an EIS, all theother determinations of non-significance aresuperseded and a coordinated review mustcommence.

• Conditioned Negative Declaration: If duringthe review of an application and the EAFsubmitted by an applicant on an UnlistedAction, an involved agency determines that thepotentially significant impacts could beeliminated or reduced to a non-significantlevel through imposed conditions, the agencymay consider using the process. Use of thisprocess requires a full EAF and coordinatedreview.

Step 4: Determining Significance• The lead agency has 20 calendar days to make

its determination of significance.• If the lead agency finds that it does not have

sufficient information to make this determina-tion, it may request that the applicant provide it.

• In determining significance, the lead agencymust consider the:- Whole action and the criteria [see §617.7(c)];- EAF and any other information provided by

the applicant;- Involved agency input, where applicable;

and- Public input, if any.

Step 5: Preparing the Draft EnvironmentalImpact Statement (EIS)

• The applicant always has the right to preparethe draft EIS. If the applicant refuses, the leadagency has the option of preparing the draftEIS, having it prepared by a consultant, orterminating its review of the action.

• All draft EIS(s) must include the followingelements:- Concise description of the proposed action,

its purpose, public need and benefits,including social and economic consider-ations;

- Concise description of the environmentalsetting of the areas to be affected, sufficientto understand the impacts of the proposedaction and alternatives;

- Statement and evaluation of the potentialsignificant adverse environmental impactsat a level of detail that reflects the severity ofthe impacts and the reasonable likelihood oftheir occurrence, etc.

Step 6: You have to determine the adequacy ofdraft EIS for public review.

• Upon receipt of a submitted draft EIS, the leadagency has 45 days to decide whether the EISis adequate for public review. If the agencydecides that the draft EIS is not adequate, itreturns the draft EIS to the applicant with awritten identification of the deficiencies. Theagency has 30 days to determine adequacy ofa resubmitted draft EIS.

• If the lead agency determines that the draftEIS is adequate, it issues a Notice of Comple-tion of a Draft EIS.

Step 7: If the lead agency determines that thedraft EIS is adequate, it issues a Notice ofCompletion of a Draft EIS.

Step 8: Public Comment Process• Filing of the Notice of Completion of a Draft

EIS starts the public comment period. Theperiod must be a minimum of 30 days, duringwhich all concerned parties are encouraged tooffer their comments. The comment periodmust continue at least 10 days following theclose of a public hearing.

Step 9: Agency needs to decide whether to holda public hearing.

• After the lead agency accepts the draft EIS, itmust decide whether to hold a public hearing– a hearing is not mandatory. If a hearing is tobe held, the lead agency must prepare and file

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a Notice of Public Hearing. The hearing cannotstart sooner than the 15th day following theNotice of Public Hearing, nor more than 60days from the date of filing of the Notice ofCompletion of the Draft EIS. If a publichearing is required under an applicable localor state law, it is not necessary to hold aseparate SEQR hearing.

Step 10: Preparation of the final EIS• The lead agency is responsible for the ad-

equacy and accuracy of the final EIS. The finalEIS should be prepared within 45 calendardays after the close of any hearings or within60 days after the filing of the draft EIS,whichever occurs last. The final EIS mustconsist of the following parts: the draft EIS,including any necessary revisions and supple-ments; copies or a summary of the substan-tive comments received and their sources; andthe lead agency’s response to the comments

Step 11: Findings – SEQR• Each involved agency must prepare its own

written findings statement, after a final EIShas been filed and before the agency makes afinal decision. The findings of each agencymust be filed with all other involved agenciesand the applicant at time of adoption.

• A positive findings statement means that theaction is approvable after consideration of thefinal EIS. It also demonstrates that the actionchosen is the one that minimizes adverseenvironmental impacts presented in the EISand weighs and balances them with the social,economic and other essential considerations.

• If the action is not approvable, a negativefindings statement with the reasons for thedenial must be prepared. The findings can befinalized no sooner than 10 days following thefiling of the Notice of Completion of the FinalEIS, and if the action involves an applicant,the lead agency’s findings must be madewithin 30 days from the filing date.

Q: What are the benefits of SEQR?A: SEQR provides many benefits to the public,

projects sponsors and agencies:For example, thepublic can participate in the SEQR processthrough:

- Participation in the scoping process for thedraft EIS.

- Reviewing SEQR documents and providecomments on them to relevant decision

makers at the agency.- Participation in SEQR hearings on an

activity’s / projects environmental impactsAlso, as a result of SEQR, agencies are required toprovide a clear and supportable record for theirdecisions.

The dSGEIS

Q: Why is the draft scope for thedSGEIS being issued?

A: The Department of Environmental Conservation,Division of Mineral Resources, is responsible forregulating production and development of gas inNew York. Natural gas companies are interested indeveloping the gas in the Marcellus Shale by usinghorizontal drilling and hydraulic fracturing. Slickwater fracturing, a hydraulic fracturing technique,requires large amounts of water. The DEC hasdecided that the process of issuing permit for wellswhen companies propose high-volume hydraulicfracturing requires further review under SEQR.Thus, the draft scope was issued as one of the firststeps in complying with the SEQR process.

· Note: For more information on complying with theSEQR process, please see the diagram summariz-ing the steps involved.

Q:How can the public meaningfullyparticipate in the dSGEIS process?

A: The DEC gives provides several opportunities forpublic participation during the drafting of theSGEIS process. The first opportunity for publicinvolvement was during the six scoping meetingsheld statewide for the express purpose of gettingpublic comments (written and verbal) on the draftscope for the dSGEIS. The public’s comments areincorporated into the final scoping document forthe dSGEIS. Once the dSGEIS has been preparedit will be released for public comment for a mini-mum period of 30 days. This is the second andfinal chance for the public to be involved. Com-ments gathered during this comment period willbe used to develop the final SGEIS document.Before the final SGEIS is completed, the DEC willissue a responsiveness summary which is awritten response to the comments and questionsraised at the public hearings.

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Q:What is the Draft Scope of thedSGEIS?

A: The draft scope of the dSGEIS addresses aspectsof high-volume hydraulic fracturing that needfurther review and looks at he potential impacts ofwater withdrawals,- transportation of water to the site,- use of additives in the water to enhance the

hydraulic fracturing process,- space and facilities required at the well cite to

ensure proper handling of water and additives,and

- removal of spent fracturing fluid from the wellsite and its ultimate disposition.

The scope also addresses visual, noise and airquality issues. Community and cumulativepotential impacts are noted as well. The scopedescribes the permit issuance process for wells,and coordination with local governments andjurisdictions.

Q:What is the Generic EnvironmentalImpact Statement (GEIS)?

A: The Generic Environmental Impact Statement wasa document finalized in 1992 and issued by theDepartment of Environmetal Conservation toevaluate its gas and oil regulatory program. TheGEIS set statewide factors that would be appli-cable for SEQR review of issuing permits for gaswells.

Q:What are the DEC’s main objectivesin carrying out the sGEIS?

A: The DEC wants to address the following potentialimpacts of gas drilling in the Marcellus Shale:• Water withdrawals;• Transportation of water to site;• Use of additives in the water to enhance the

hydraulic fracturing process;• Space and facilities required at well site to

ensure proper handling of water and additives;• Removal and disposal of fracking fluids;• Noise, visual, and air quality impacts; and• Cumulative and community impacts.

Q: What are some of the criticismsthe Draft Scope for the sGEIS hasreceived?

A: • Commitment not to reopen clear deficiencies of 1992 GEIS.• Vague or absent descriptions of methodologies

of how studies and analysis will be conducted.

• Refusal to assess the impacts of associatedpipelines, transmission lines, compressorstations, or accidental spills or emissionsbecause theses impacts are not the within thedivision’s jurisdiction.

• Most deficient in the areas of cumulative im-pacts, risk assessment, air quality, staffingissues, significant habitats, community impacts,best industry practices and public participation.

Environmental Assessment

Q: What are the steps of New York’sreview and evaluation process?

A: First Step:The first step is known as the scoping process.During this period of time, the public has theopportunity to comment on the Draft Scope for theSupplemental Generic Environmental ImpactStatement (SGEIS) during statewide scopingmeetings. During these meetings, the public canexpress their concerns, criticisms and suggestionsabout the scope of the SGEIS through verbal orwritten comments.

Second Step:The comments generated from the scoping meet-ings are incorporated into a final scoping docu-ment for the SGEIS, which summarizes the issuesregarding natural gas drilling in the MarcellusShale.

Third Step:The final scope is used to create the Draft Supple-mental Generic Environmental Impact Statement(dSGEIS), which is supposed to address all of thepotential environmental affects created by drillingin the Marcellus Shale not addressed in the 1992Final Generic Environmental Impact Statement(fGEIS).

Fourth Step:The public is given the opportunity to commentand review the dSGEIS, which will be used tocreate the final SGEIS.

Fifth Step:A Final Supplemental Generic EnvironmentalImpact Statement (“fSGEIS”), along with a Find-ings Statement, is issued from public comments,additional information and responses to com-ments.

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Q: What is the DEC’s policy onmitigating and assessing visualimpacts?

A: According to the DEC’s Assessing and MitigatingVisual Impacts Program Policy, facilities “locatedin visual proximity to sensitive land uses canproduce significant visual impacts.” Thus, theDEC’s policy and guidance defines what visualand aesthetic impacts are, describes when a visualassessment is necessary and how to review avisual impact assessment, differentiate State andlocal concerns, and defines avoidance, mitigationand offset measures that eliminate, reduce, orcompensate for negative visual effects.

The policy issued by the DEC makes clear that itdoes not reduce an applicant’s responsibility tolocal and other state agencies and departments toaddress aesthetic and visual issues. The DEC’sguidance is meant to “provide a mechanism forcomplying with the balancing provisions of theState Environmental Quality Review Act (SEQR)with respect to environmental aesthetics.” Thepolicy also helps to define aesthetic concerns ofstatewide significance from those of local signifi-cance. The staff of the DEC is generally respon-sible for identifying and mitigating impacts toaesthetic resources that have been designated ofstate and federal significance. There is a prefer-ence to leave resources designated as local to localdecision makers because they “are likely to bemore familiar with and best suited to addressthem.”

Q:How does the policy work?A: When an organization applies for a permit ap-

proval from the DEC, “staff must evaluate thepotential for adverse visual and aesthetic impactson receptors outside of the facility or property.”When gas drilling sites are potentially within the“viewshed” of an area designated as an aestheticresource, visual assessments are required before apermit will be approved. If the visual assessmentidentifies significant visual impacts, then the gascompanies will be required to “employ reasonableand necessary measures to either eliminate,mitigate or compensate for adverse aestheticeffects.” Since such measures will be important inhelping to reduce the negative visual conse-quences that gas drilling could create, it is impor-tant to understand how the visual assessmentprocess works and what exactly are designatedaesthetic resources.

When reviewing an application for a permit, DECstaff have the responsibility of evaluating thepotential for negative aesthetic effects on sensitiveplaces. SEQR requires the DEC to mitigate to themaximum extent practicable significant adversevisual impacts identified during the permit appli-cation process. SEQR requires the balancing ofthe cost of the mitigation measures and theirpracticality.

While reviewing applications, DEC staff mustensure that all aspects of aesthetic and visualconcerns are addressed, including impacts fromall project components and their operation on allinventoried resources. In addition, an equitablelevel of expectations between the potential signifi-cance of the impact, the degree of sophistication ofthe analysis required of applicant and appropriatelevel of mitigation strategies must be established.The goal of visual assessment is to reveal impactsand effective mitigation strategies.

The Department has identified certain basic stepsthat its staff must take to make sure that concernsare fully reviewed in each permit application:1. Verify the applicant’s inventory of aesthetic

resources.2. Verify the applicant’s visual assessment, using

either graphic viewshed and line-of-sight profileanalysis as illustrated in Appendix A, or moresophisticated visual simulations and digitalviewshed analysis, as needed.

3. Determine or verify the applicant’s assessmentof the potential significance of the impact.

4. Confirm that applicant’s mitigation strategiesare reasonable and are likely to be effective, orassure mitigation by requiring the applicant tosubmit a design that includes the requiredmitigation, or, impose permit conditionsconsistent with those mitigation requirements.

Q: What is an environmentalassessment?

A: An environmental assessment is a process ofevaluation the known or potential environmentalconsequences of a proposed activity. During theenvironmental assessment process, agencies areprovided with an opportunity to “identify theirconcerns about an action, provide guidance to thelead agency in making its determination of signifi-cance, and help determine whether additionalrelevant information about potential impacts isneeded.” (DEC website: SEQR Handbook – Envi-ronmental Assessment Chapter)

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Q: What is an Environmental AssessmentForm (EAF)?

A: The EAF is a form specifically developed for SEQRthat “provides an organized approach to identify-ing and assessing the information needed by thelead agency as it makes its determination ofsignificance” (DEC website, SEQR Handbook –Environmental Assessment Chapter). The properlycompleted form will do the following things:• Describe the action;• Indicate the location of the proposed action;• State the purpose of the action; and• Describe the potential impacts on the

environment of the action.

Recommendations

Q: What are some recommendationsfor resolving landscape issues inthe Marcellus Shale?

A: • Add gathering lines to coverage of SGEIS.• Address the deficiencies of 1992 GEIS, e.g.,

cumulative impacts.• Scoping sessions and other public hearings

related to Marcellus Shale should be primarilyheld in areas most likely to see the impacts ofthe proposed drilling activity.

• Provide more detailed descriptions of methodolo-gies of how studies/analysis will be conductedin SGEIS.

• Encourage DEC to address the impacts ofassociated pipelines, transmission lines, com-pressor stations, etc. (impacts not withindivision’s jurisdiction).

• Get the DEC to address & improve staffingissues. It is clear that right now the DEC isunderstaffed & inexperienced to deal with thegas drilling issues.

• Local jurisdictions should be encouraged todevelop policies to regulate visual impacts of gasdrilling, e.g., Assessing & Mitigating VisualImpacts.

• DEC should track / regulate the process gascompanies use to dispose of produced water, i.e.waste.

• Make sure that regional DEC offices overseeingwells get familiarity / training with gas drilling.

• Work with gas companies, soil and waterconservation districts and other local organiza-tions, e.g., DEC should work with the Delawareand Susquehanna River Basin Commissions todevelop a well coordinated system that regulateswater withdrawal, water use and quality.

• Encourage the gas drilling companies to haveextensive inspections and supervision during allthe phases of the gas drilling process – fromsurveying and drilling through gas productionand final reclamation of land.

• To mitigate noise and traffic disruptions, makesure that companies are encouraged to providetheir movement schedules to local traffic depart-ments, 911 emergency services, etc. Also,request companies to schedule their movementsand other activities around certain times suchas rush hour, school bussing times, etc.

Landscape Issues

Q: What are some effects of naturalgas drilling that we should beworried about?

A: • Water quality & availability• Visual and aesthetic impacts• Noise levels• Pollution – chemicals from drilling process

- these chemicals are unknown – companiessay that the composition is a “trade secret”

• Endangering the habitats of certain species ofbirds, etc.

Q: What is the geology of theMarcellus Shale?

A: • Devonian Black Shale– Low density fissile shale– Carbonaceous (organic rich)– Vertical natural fractures– Low permeability– Slightly radioactive

Q: What is the Susquehanna RiverBasin Commission (SRBC)?

A: The SRBC is a federal-interstate compact commis-sion established by the federal government andthe states of New York, Pennsylvania, and Mary-land. The SRBC is responsible for managing thebasin’s water resources.

Q:Do the states play any role in CleanAir Act (CAA) enforcement?

A: Yes. A state may require a pipeline to comply withoverall air quality requirements under the CAAthrough its state implementation plan (SIP). A SIP“may establish enforceable emission limitations forparticular emission sources, permitting programs

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for the construction of new or modified air pollut-ant-emitting facilities, and other control measuresapplicable to emission sources within the state toensure that the National Ambient Air QualityStandards will be achieved and maintained withineach air quality control region within a state”http://www.steny.org/usr/observations%20on%20gas%20production%20on%20marcelus%20shale(REV).pdf at 13.

Q:Do compressor stations requireClean Air Act (CAA) permits?

A: Yes, commonly they do. Compressor stations “maytrigger requirements under several CAA programs,including the New Source Review (NSR) andPrevention of Significant Deterioration (PSD)program and the permitting program for majorstationary sources under Title V of the CAA. TheNSR program applies to new source constructionand proposals to conduct major modifications ofexisting industrial facilities that are located in“non-attainment” areas (i.e., regions with poor airquality that do not satisfy the National AmbientAir Quality Standards), while the “Prevention ofSignificant Deterioration” requirements apply toproject proposals that are located in areas whichare in “attainment” with applicable NationalAmbient Air Quality Standards (i.e., ambient airquality in the region surrounding the new ormodified source complies with the nationalstandards).” http://www.steny.org/usr/observations%20on%20gas%20production%20on%20marcelus%20shale(REV).pdf at 12-13.

Q:Will the DEC ever enact regulationswithout any prior notice?

A: Not unless there is an emergency and action mustbe taken to “prevent waste, pollution or to protectcorrelative rights.” Such emergency provisions areonly effective for 15 days. Normal orders, rules,and regulations must be given a public hearingafter 10 days notice. 6 NYCRR 550.4.

Accommodation Doctrine

Q:What is the accommodation, alsoknown as alternative means,doctrine?

A: The accommodation doctrine is also known as thealternative means doctrine. The doctrine balancesthe rights of a mineral owner and a surface ownerin the use of a surface. A lessee may be required

to adopt an alternative by the rules of reasonableusage if: 1) an existing use by the surface’s ownerwould otherwise be impaired, and 2) the lesseehas alternatives under establishes industrypractices whereby the minerals can be recovered.32 Tex. Jur. 3d Eminent Domain § 496.

Q:When is the accommodationdoctrine used? When does theaccommodation doctrine apply?

A: The accommodation doctrine applies “in determin-ing whether inverse condemnation of a mineralestate occurs when a governmental entity thatown the surface estate restricts the use of thesurface by the mineral owner and lessee. Thegovernmental surface owner bears the burden ofproving that the use of the surface by the lessee isnot reasonably necessary. This proof may be madeby showing that noninterfering and reasonableways and means of producing the mineral areavailable, and that their use will permit thesurface owner to continue the existing use of thesurface.” 32 Tex. Jur. 3d Eminent Domain § 496.

WWWWWell Spacing and Sitingell Spacing and Sitingell Spacing and Sitingell Spacing and Sitingell Spacing and Siting

Q:What are the regulations dealingwith well spacing in New York?

A: NYCRR 553.1 outlines well spacing rules in NewYork. In general, oil and gas wells:- cannot be located less than 660 feet from any

boundary line of the lease, integrated leases orunit, and

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

Generally, a well with a lease, integrated lease, orunit that uses the New York-Pennsylvania borderas one of its boundary lines may not be drilledwithin 330 feet of the border.

The Final Scope for the Draft SGEIS includes wellspacing as one topic for which the DEC is consid-ering issuing new regulations because of the largenumber of wells that will likely be drilled. For moreinformation, please see the Final Scope § 2.1.6,well density, starting on page 17.

Q:How far must a well be from abuilding under the DEC permits?

A: NYCRR 553.2 classifies the distance a well mustbe from a building according to “building” type. Awell cannot be located:


- inhabited private homes: closer than100 feetfrom any home without the owner’s writtenconsent;

- public buildings: closer than 150 feet from any“public building or area which may be used as aplace of resort, assembly, education, entertainment, lodging, trade, manufacture, repair,storage, traffic or occupancy by the public;”

- roads: closer than 75 feet “to the traveled part ofany State, county, township, or municipal roador any public street, road or highway;”

- public river, stream or other body of water:nearer than 50 feet.

This regulation, which is adopted in the interest ofpublic safety, does not apply to a building orstructure which is incident to agricultural use ofthe land on which it is located, unless suchbuilding is used as a private dwelling house or inthe business of retail trade.

Q:How does the DEC determinespacing unit size?

A: The Environmental Conservation Law establishescriteria for spacing unit sizes and how close thewell can be to the unit boundaries.

Q:When must the DEC issue a spacingunit permit?

A: The DEC must issue a permit if an applicantcontrols 60% of the acreage and a proposed unitconforms to the Environmental ConservationLaw criteria. “The DEC will not issue permits forwells with proposed spacing units that createstranded acreage that cannot be developed.”http://www.dec.ny.gov/

Q:Will the DEC ever force a welloperator to revise a spacing unit?

A: “The DEC may only modify a unit previouslyestablished by a permit or a spacing order afterall affected parties have had an opportunity tocomment. Such Department-initiated modifica-tions are very rare. The rumor that the DECchanged a spacing unit most often arises whenan operator forms a voluntary unit, in accor-dance with the pooling clause in its leases, thatis different from the spacing unit establishedunder the Environmental Conservation Lawwhen the DEC issues a well permit. Operatorsare not required to inform the DEC of voluntaryunits, and the DEC does not track them. How-ever, only the spacing units established by DECpermits and orders are recognized for thepurposes of compulsory integration and futurewell permitting in a given area.” http://www.dec.ny.gov/

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BackgroundDifferent Federal and State agencies are involved

with pipeline regulation depending primarily on whattype of pipeline it is and where it is located. Thefollowing questions can help guide the reader inproperly categorizing the pipeline. Once one or moreagencies are identified the reader will know whichregulations apply.

Regulations

Q:Which federal authorities regulatepipelines?

A: • Federal Energy Regulatory Commission (FERC)(http://www.ferc.gov/)

• Department of Transportation (DOT) (http://www.dot.gov/)

• Natural Gas Pipeline Safety Act of 1968• Occupational Safety and Health Administration

(OSHA) (http://www.osha.gov/)• Environmental Protection Agency (EPA) (http://

www.epa.gov/)

Q:What state authorities regulatepipelines?

A: • New York Department of EnvironmentalConservation (DEC) (http://www.dec.ny.gov/)

• New York Public Service Commission (PSC)(http://www.dps.state.ny.us/)

• New York State Department of Agriculture andMarkets (http://www.agmkt.state.ny.us/)

Q:What pipelines does the Departmentof Public Service (DPS) regulate?

A: Gathering lines — 16 NYCRR 255.9Service lines — 16 NYCRR 255.361Transmission Lines — 16 NYCRR 255.301 et seq.

Q:How are pipelines categorized?A: Size:

Length and diameter are used in many of theregulations to demarcate which authority hasjurisdiction over the pipeline. Length is measuredin feet or miles while diameter refers to a cross-section of the pipe and is in inches.

Pressure:Pressure is measured in pounds per square inch(PSI) of pressure that the pipe will be operating at.One hundred and twenty five PSI is a commoncut-off in distinguishing between smaller pipelines(known as gathering lines or service lines) andlarger lines (known as transmission lines).

PurposeThe intended or actual use of the pipeline can alsodetermine what agency is responsible for oversee-ing compliance with applicable regulations. Forexample, some pipes are used for service, othersfor collection or bulk sale, and others for intra- orinter-state transmission.

LocationLocation of the pipelines also governs who regu-lates and can help the reader find answers relat-ing to, inter alia, siting, eminent domain, and thepermit and construction process. The readershould take note whether the land fits within oneor more of the following categories of land:• Federal,• State,• Private unleased, or• Private leased. Once pipelines are categorized using the abovecriteria the reader will be able to navigate theregulations and search out answers to specificquestions about the pipeline at issue.

Pipelines


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Q:What aspects of the pipeline doregulations generally address?

A: Regulations vary greatly in their scope dependingon the authority of the agency involved. Groundcoverage, pipeline location and spacing are somecommon pipeline features that the regulationsaddress.

Ground Coverage, Locationand Spacing

Q: How deep must pipes be buried?A: Depth is measured from the top of the buried pipe

to the surface. The depth can be dependent onmany factors such as whether the pipe is under-neath farmland or water. Also, exceptions aresometimes made to required depths when the pipemust pass over rocky soil. The regulations aredetailed and should be consulted directly for thisinformation.

Q:How is pipe location determinedand what factors guide thisdecision?

A: Environmental sensitivity of the area, availabilityof land, and need for the pipeline to take a certainroute are common factors that influence the sitingof pipelines. The showing that must be made byan entity seeking approval for a new pipelinevaries depending on the regulatory agency. Theregulations should be consulted directly.

Q:To what extent do pipes have to beplaced in the same easement/trench line?

A: Most of the regulations require that the pipelinesbe placed, when feasible, in existing trench linesand that new pipes be consolidated wheneverpossible. In the context of gathering lines (smallscale gas lines) there is less likelihood that pipe-line sprawl will be minimized because the natureof the pipelines themselves.

Q:Which, if any, gathering lines areregulated under the DEC?

A: Gathering lines that cross environmentally sensi-tive areas are subject to DEC jurisdiction. Accord-ing to counsel for the DEC, the environmentalprovisions are essentially the same as those

imposed by the DPS—the agency responsible forregulating gathering lines—rendering DEC super-vision superfluous.

Q:How are rights-of-way grantedacross federal lands?

A: Rights-of-way through federal public lands,including the United States forest reserves, maybe granted “by the Secretary of the Interior toqualified persons for a pipeline to transport oil ornatural gas, or for a pumping station. Permissionmay be granted for the ground occupied by thepipeline and 25 feet on each side.”http://web2.westlaw.com/result/do

Q:What showing must FERC make fora new right-of-way to be granted forgas pipelines?

A: The Federal Energy Regulatory Commission’sfinding of a need for a proposed natural gaspipeline project must be supported by substantialevidence, as required by § 19(b) of the Natural GasAct (15 U.S.C.A. § 717r(b)).http://web2.westlaw.com/result/[FN6] Louisiana Ass’n of Independent Producers

& Royalty Owners v. F.E.R.C., 958 F.2d 1101(D.C. Cir. 1992).

Q:What is the size of the easementgranted for use of the pipes?

A: Easement sizes vary from a very small width tomany meters across. The width is generallygoverned by the size of the pipe to be buried andthe need to access the easement for excavating orfor future maintenance. Safety is also a concern:higher capacity pipes are generally set off furtherfrom buildings and uncleared land.

Q:What environmental protectionsare required?

A: Environmental criteria for siting a pipeline arefairly encompassing. Regulations for many of thetransmission lines require extensive environmen-tal mitigation measures to be taken in order for apipeline permit to be issued.

Q:How difficult is it to obtain a permitfor this category of pipeline?

A: In general, the larger the pipeline and the morecorrelated its intended use to large scale convey-ance of gas, the more arduous the permitting


process will be. The regulations also provide forvarying degrees of public notice and opportunity tocomment on the proposed pipeline.

Q:Who regulates permitting andsiting for new interstate gastransmission pipelines?

A: The Federal Energy Regulatory Commission(FERC) is responsible for permitting and sitinginterstate gas transmission lines. The authorizingstatute for this authority is the Natural Gas Act of1938 which grants FERC authority to reviewinterstate pipeline proposals. FERC can coordinateplacement with state and local groups and cancontrol transmission line routes. (http://www.steny.org/usr/)

Q:What width of easement is grantedfor a pipeline?

A: The width of the easement is determined duringthe permit application process for the proposedpipeline. If, however, the land is privately leasedland, the easement is implied and is subject to theterms of the lease agreement.

Q:What are the different ways land isacquired for pipeline routes?

A: • Easement (contractual)• Takings• Condemnation

Q:Is there a difference between aright-of-way and an easement?

A: Effectively not. The difference is in name andgenerally is a product of the process by which theland was acquired.

Q:Can you put switch-grass to on topof right-of-ways?

A: Likely not. Most right-of-way regulations requirethat the area be kept free of brush and debris soas to allow access as well as for safety concerns(e.g. fire). This is not to say that a special land userequest cannot be submitted to the governingagency during the permitting process. However, itis difficult to ascertain from the language of theregulations how the agency staff will respond tothis type of a request.

Q:Who controls the use of right-of-ways?

A: The agency to which the pipeline applicant sub-mitted its proposal controls the use of the right-of-way. Any proposed use of the right of way must becleared with that agency. Other entities such asmunicipalities are preempted from allowing anyother use inconsistent with the agencies regula-tions.

Pollutants and Storm Water Discharges

Q:Can anyone regulate pollutantdischarge from pipelines?

A: Yes, under the Clean Water Act (CWA) nationalpollutant discharge elimination system (NPDES)permits can be required for “discharge of processor test water during construction and operation ofpipeline facilities.” Administration of this program,the Section 404 permit program, can be trans-ferred to the states by the EPA administrator. 33C.F.R. § 323.5. In New York, the EPA has trans-ferred authority to the New York DEC. It should benoted, however, that the Energy Policy Act (seenext question) affected the level of pipeline pollut-ant discharge regulation. (http://www.steny.org/usr/)

Q:Did the Energy Policy Act of 2005exempt storm water dischargesresulting from the construction ofnatural gas pipelines from theNPDES permit requirements?

A: Sort of. The DEC can still require NPDES permits“when the discharge of a pollutant other thansediment contributes to a violation of an appli-cable water quality standard.” See 40 C.F.R. §122.26(a)(2)(ii).

As a general rule, however, the EPA exemptsnatural gas pipeline construction from NPDESpermit requirements. (http://www.steny.org/usr/)

Safety and Maintenance

Q:Who regulates the safety of interstategas transmission lines?

A: The National Gas Pipeline Safety Act governssafety requirements for interstate gas transmis-sion lines and expressly preempts more stringent

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regulation of such lines by state agencies. See 49U.S.C. App. § 1672(a)(1).

Q:Who is responsible for making surethat pipelines maintain theirintegrity as they age?

A: The United States Department of Transportation(DOT). Under the Pipeline Safety Improvement Actof 2002, pipeline operators must prepare andimplement an “integrity management program”(IMP). The IMP requires that high risk areas beidentified (referred to as “High ConsequenceAreas”) and that risk analysis be done on theseareas. Additionally, the entire pipeline systemmust be given periodic integrity assessments. Thepipelines must be re-inspected every seven years.

Q:The Pipeline Inspection, Protection,Enforcement, and Safety Act of2006 (PIPESA) made revisions toIMP’s under the Pipeline SafetyImprovement Act of 2002; what didit add?

A: 1.Minimum standards for IMPs for distributionpipelines (including installation of excess flowvalves on single family residential service lines onthe basis of feasibility and risk);2.Standards for managing gas and hazardousliquid pipelines to reduce risks associated withhuman factors (e.g., fatigue);3.Authority for the Secretary to waive safetystandards in emergencies;4.Authority for the Secretary to assist in restora-tion of disrupted pipeline operations;5.Updated incident reporting requirements;6.Requirements for senior executive officers tocertify operator integrity management performancereports;7.Clarification of jurisdiction between states andPipeline and Hazardous Material Safety Adminis-tration (PHMSA), a division of the DOT, for shortlaterals that feed industrial and electric generatorconsumers from interstate natural gas pipelines.”(http://www.steny.org/usr/)

Q:What about the danger that buriedpipelines will be hit and rupturedduring excavation?

A: This is one of the concerns that the 2006 Act(PIPESA) sought to address. Excavators arerequired to call before they dig so that pipeline

operators can locate the buried pipelines. The DOTmay enforce penalties against a variety of entitiesunder the 2006 Act, including penalties against:• Excavators: if excavators do not report damage

to pipes or gas released during excavation or ifthey disregard buried pipeline markers, theDOT may impose penalties.

• Pipeline Operators: if pipeline operators fail torespond to a locating request or do notaccurately mark the location of the buriedpipes, the DOT may impose penalties.(http://www.steny.org/usr/)

Q:Does the new GEIS being formu-latedby the DEC include gas gatheringlines, transmission lines, orancillary facilities such ascompression stations?

A: No. The Public Service Commission, not the DEC,regulates gathering lines, transmission lines, andcompession stations.

Q: Can a landowner build over buriedpipelines?

A: Generally not. Buildings should not be con-structed over pipelines for obvious reasons, butother uses of the land may be possible such asfarming or placement of a road. As such, ownersshould make sure that their leases specify thelocation(s) of possible future construction. If theland is taken by eminent domain or condemnationthen above-ground use is more limited. Land useabove the pipelines is site specific so the regula-tions should be consulted directly.

Technical DPS Regulatory Questions

Q:What are the DPS regulations forpipelines extending more than1000 ft but less than ten miles witha PSI of 125 or more?

A: The application for construction of these pipelinesmust include:• two copies of the the Environmental Manage

ment and Construction Standards and PracticePractices setting forth the protocols that mustbe followed “to protect and minimize the impactto the environment during installation andmaintenance of all such lines,” and

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• two certified statements agreeing to install andmaintain the lines as directed by the DPS. 16NYCRR 85-1.1;http://www.dps.state.ny.us/articlevii_Gas.pdf.

The Notice of Intent for pipelines < 5 miles and <6" in diameter must include:• the intended date for construction to begin;• a map and description of the path the line will

take, including the length of the pipe, the depthit will be buried, the maximum allowable operating pressure, right of way width, width of anyarea to be cleared, any known undergroundfacilities to be crossed or paralleled, wellsconnecting to the line, the point where theline connects with another line, existing andproposed access roads, location of compressorstations (detailed description), and the name ofevery municipality the line will cross;

• the zoning and environmental conditions of thelands the pipeline will cross need to be thoroughly detailed. Also included are scenic areas,historic landmarks and other visual resources.16 NYCRR 85-1.2

The Notice of Intent for all other pipeline diametersand lengths under 10 miles must include every-thing listed in the NOI above, plus:- property boundaries;- any dwelling within 150 feet;- a statement explaining the need for the line,

including a demonstration that a market orspecific purchaser for the gas will exist.

- any other information the applicant considersrelevant;

- needs to be served on the groups listed in theNOI above plus the Department of Transportation, the Commissioner of Agriculture andMarkets, the State Archeologist, the StateHistoric Preservation Officer, the chief executiveofficer of any municipality the line enters, andany other state agency that has authorityover environmental standards. Also, county andtown planners will expedite the certificationprocess. 16 NYCRR 85-1.3

Q:What are the DPS regulations forpipelines extending more than 10miles with a PSI of 125 or more?

A: The application must include:- description of the proposed facility;- statement of the location of the proposed site or

right-of-way;- summary and description of any studies which

have been made of the environmental impact ofthe proposed project;

- statement explaining the need for the proposedfacility;

- description of any reasonable alternate locationsor routes for the proposed facility, including adescription of the comparative merits and detri-ments of each location or route and a statementexplaining why the primary location or route isbest suited for the proposed facility; and

- other information as the applicant deemsnecessary or desirable. 16 NYCRR 85-2.1 etseq.; see also http://www.dps.state.ny.us/articlevii_Gas_Elect.pdf.

Q:What action will the DPS take if itdetermines that more informationis required before a permittingdecision can be made?

A: The commissioner or the presiding officer mayrequest additional studies or materials that theapplicant must then provide.16 NYCRR 85-2.5.

The exhibits that must be attached to a permitapplication are a great way to see what consider-ations the permit requesting entity must take intoaccount during its decision making process. Oncethe exhibits are filed they are available publiclyand should be consulted to see if comment orintervention is needed in order to address otherconcerns.

The following excerpts are taken directly from theNew York regulations and give a few examples ofwhat must be included in exhibits:

1. Section 86.3. Exhibit 2: location of facilities.(a) The applicant shall submit detailed maps,

drawings and explanations showing the right-of-way for each proposed facility. Such maps,drawings and explanations shall include:

(1) New York State Department of Transportationmaps (1:24,000 topographic edition), showing;(i) the proposed right-of-way (with control

points indicated), covering an area of atleast five miles on either side of theproposed facility location;

(ii) where the construction or reconstructionof the proposed facility would necessitatepermanent clearing or other changes tothe topography, vegetation or man-madestructures.

(iii) any known archaeologic, geologic,historical or scenic area, park or un-

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touched wilderness on or within threemiles of the right-of-way;

(2) New York State Department of Transportationmaps (scale 1:250,000) showing the relation-ship of the proposed facility to the applicant’soverall system with respect to:(i) the location, length and capacity of the

proposed facility, and of any existingfacility related to the proposed facility;

(ii) the location and function of any structureto be built on, or adjacent to, the right-of-way;

(iii) the location and designation of each pointof connection between an existing andproposed facility; and

(iv) nearby, crossing or connecting rights-of-way or facilities of other utilities.

2. Section 86.5. Exhibit 4: environmental impact.(a) The applicant shall submit a statement de-

scribing any study which has been made ofthe impact of the proposed facility on theenvironment. That statement shall include adescription of the methods employed inmaking that study and a summary of itsfindings.

(b) The applicant shall state:(1) what changes, if any, the construction

and operation of the proposed facilitymight induce in the physical or biologicalprocesses of plant life or wildlife throughany permanent or significant temporarychange in the hydrology, topography orsoil of the area;

(2) what efforts, if any, have been made toassure:(i) that any right-of-way avoids scenic,

recreational and historic areas;(ii) that any right-of-way will be routed to

minimize its visibility from areas ofpublic view;

(iii) that any right-of-way has beenplanned to avoid heavily timberedareas, high points, ridge lines andsteep slopes; and

(iv) that the selection of any proposedright-of-way preserves the naturallandscape and minimizes conflict withany present or future planned landuse;

(3) what, if any, plans have been formulatedto keep any right-of-way clearing to theminimum width necessary to preventinterference of vegetation with the pro-

posed facility;(4) what, if any, schedule or method of

clearing the right-of-way has been formu-lated to take into account soil stability,protection of natural vegetation, and theprotection of adjacent resources (includingthe protection of any natural habitat forwildlife);

(5) what, if any, plans have been made toprotect vegetation and topsoil not cleared,from damage from construction andoperation of the facility;

(6) what, if any, provision has been made toprotect fish and other aquatic life fromharm from the use of explosives or pollut-ants in or near streams and other bodiesof water;

(7) what, if any, pesticide or herbicide will beused in construction or maintenance ofthe proposed facility (including thevolumes and manner of use);

(8) what, if any, plans have been made tolocate and design appurtenant structuresto minimize the environmental impact ofthe structures (including visual and noise

disturbance); and(9) what, if any, provisions have been made for

cleanup and restoration of the project areaafter construction.

(c)(1) If any portion of the proposed facility is tobe constructed underground, the applic-ant shall state what, if any, provisionshave been made to avoid clearance of theentire right-of-way. If the clearanceproposed will go to the mineral soil, theapplicant shall state:(i) the width of the clearance;(ii) what, if any, provisions have been

made for the replacement of topsoilremoval during construction;

(iii) what, if any, provisions have beenmade for removing excess soil excavated during construction; and

(iv) what, if any, plans have been madefor stabilizing the cleared area withvegetation and erosion control devices.

(2) If any underground portion of the pro-posed facility will be constructed in oradjacent to a stream or other body ofwater, the applicant shall state:(i) what, if any, plans have been made to

prevent erosion of the banks;(ii) what, if any, techniques (such as

cofferdams) will be used; and(iii) what, if any, plans have been made to

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use the water from such streams orother bodies of water for pipe-testingor other purposes (including volumesof water involved and methods forrelease of water once used).

Additionally, construction data is set out in Exhibit G-4and provides a good indication of what pipes will beused and how many compressor stations areanticipated. 16 NYCRR 87.4

Public Participationfor Siting and Construction

Q:Who may file comments on theproposed pipeline?

A: Once a NOI is filed, any person may file commentson it. 16 NYCRR 85-1.7

Interested groups or persons are invited andencouraged to consult with the staff of the com-mission on any part of the proposed line. 16NYCRR 85-2.6

Other groups may intervene in the DPS proceedingif they meet the following definition:Any domestic non-profit organization or groupformed; to promote conservation or natural beauty,to promote the environment, personal heath or otherbiological values; to preserve historic sites; topromote consumer interests; to represent theinterests of commercial or industrial groups; topromote the orderly development of the areas inwhich the facility is proposed to be located.

These groups may participate in a certificationproceeding if they file a notice within 30 days afterthe date given in the public notice as the date forfiling of the application.

Other groups not fitting the above definition canintervene if they can show that they would providebeneficial insight or promote the public interest.16 NYCRR 85-2.11

Q:Who may intervene as a matter ofright in a proceeding to grant aDPS permit?

A: 16 NYCRR 8502.11(a) outlines who can participatein a certification proceeding for a DPS permit, aslong as they have made a timely application forparticipation:• state agencies, such as the DEC, the Depart

ment of Agriculture and Markets, and the Officeof Parks, Recreation and Historic Preservation

• any municipality entitled to receive notice under16 NYCRR 85-2.10(a)(1)

• any individual resident in a municipality entitledto receive notice under 16 NYCRR 85-2.10(a)(1)

• any domestic nonprofic corporation or association, formed at least in part to:- promote conservation or natural beauty- protect the environment, personal health or

other biological values- preserve historic sites- promote consumer interests- represent the interests of commercial and

industrial groups, or- promote the orderly development of the areas

in which the facility is proposed to be located

This section is quite inclusive and allows for broadparticipation on a local basis by municipalitiesand public interest organizations.

In addition to the groups listed above, 16 NYCRR85-2.11(c) allows other persons or organizationsnot listed in 16 NYCRR 85-2.11(a) to requestpermission to intervene in a DPS certificationproceeding. These persons or organizations mustinclude the following items in a request for permis-sion:• the information specified in paragraph (1) of

this subdivision, and• an explanation of how their intervention would

be “likely to contribute to the development of acomplete record or why it would otherwise befair and in the public interest.”

Requests for non-listed persons and organizationsis governed by 16 NYCRR 4.3.

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Appendix AGas Leases

Q:What is a lease?A: A lease is a legally binding contract that grants

both rights and obligations to the parties who signit. Entering into a lease agreement does notnecessarily mean that a well will be drilled on yourproperty. For information about lease terms,please see the glossary section of this guide.

Q:To what extent are leased landssubject to regulation?

A: “Private leases are not subject to DEC’s jurisdic-tion, nor are local governmental interventiontypically involved.” http://www.steny.org/usr/observations%20on%20gas%20production%20on%20marcelus%20shale(REV).pdf

Because of the apparent absence of regulation inleased lands the mitigation measures relating toenvironmental harms are generally left up tocontract agreement.

To this end, provisions that can be incorporatedinto leases become important for two reasons.1.The provisions of leases, if the only way to

ensure environmental protection, need to beproperly written to ensure this protection.a. What should those provisions be?b. What provisions have been placed in leases

or should be placed in leases are beneficialor protect the areas of concern sought to beaddressed.

2.How can leassors increase their bargainingposition with respect to the drilling or pipelinecompanies? Leverage directly relates to theamount of protective provisions that can beplaced in leases.

Additionally, the measures that landowners cantake to increase their position can also insuregreater uniformity from one piece of leased land tothe next because of collective bargaining.

Q:What are some landowner protectiveprovisions that can be added intoleases?

A: • Require groundwater testing at various timesthroughout the process. Preferably by anindependent testing entity.

• Procedures for wastewater disposal• Specify an emergency response plan.• Description of the drilling technique to be used.• Access road provisions. Location, size, and

number.• Distance minimums between wells and existing

buildings on the property or areas of theproperty where development is anticipated.

Q:How are royalties calculated undernatural gas leases in New York?

A: Royalties are calculated according to the terms ofthe lease. In general, the amount owed to thelandowner will be a given percentage (usuallyexpressed as a fraction, e.g. 1/8th) of the profitsfrom the gas sales. Profits are also determinedaccording to the lease terms but can generally beunderstood as gross sales of the extracted gasminus operating costs and expenses.

Q:Will I only receive a royalty fromcommencement of production if Ilease to the well operator who drillsthe well? If I don’t lease, or leaseto someone else, will my royaltywill be delayed?

A: “If your acreage is within a spacing unit and youdo not lease then your rights will be addressed bythe compulsory integration process (see “Compul-sory Integration” section below). If gas is sold fromthe well in the unit and you elect to be an “Inte-grated Royalty Owner” you will receive a royalty for


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production. The well operator must pay “IntegratedRoyalty Owners” promptly and no less frequentlythan it pays its lessors. If the integration order isissued before the first product sales, royalties willbe paid when production begins. If you lease toanother company (other than the operator) whoparticipates in the well, then you will be paid byyour lessee from the beginning of production ifthat is what your lease requires.”See Gas Lease questions on the DEC website athttp://www.dec.ny.gov/

Q:Can the fine print in standard,pre-printed forms be changed?

A: Lease terms are negotiable and you shouldconsider that the contract was likely written veryone-sided. Negotiate interests you wish to pre-serve.

Q:Do standard oil and gas leases willallow the operator to store gas intanks on my property?

A: No. “Oil and water may be stored in tanks on sitebut producing wells convey gas off of the propertythrough gathering lines. These undergroundgathering lines bring the gas to a sales meter andthen to an end-user or major gas transmissionline. If the well is on-line, gas flows through thegathering system. If the well is shut-in, gasremains in the wellbore and in the undergroundrock formations. Some proposed leases containterms that allow the lessee to store the gas under-ground but, like other lease provisions, this isnegotiable.”See Gas Lease questions on the DEC website athttp://www.dec.ny.gov/

Q:If I sign a lease am I transferringpossession of my property, allowingthe gas company to tear down myhouse to drill a well?

A: No. An oil and gas lease will place obligations onthe lessee and lessor which should be fullyunderstood before signing the lease but theseprovisions do not allow the lessee to destroyexisting buildings. It should be noted however thata lease is different from a purchase agreement ormineral deed which do involve the transfer ofproperty.

Q:Is it better to seek compensationthrough the compulsory integrationor forced pooling process ratherthan by an oil and gas lease?

A: Only individual assessment of the pro’s and con’sof each option on a case by case basis can bemade. Landowners should consult their attorney.

Q:If I leased is all of my acreage partof the spacing unit and is productionallocated to all of my acreage?

A: “Until the Department issues a well permit, thereis no certainty about where a well will be or whatthe spacing unit will look like. If the well permithas been issued or an application for one hasbeen received, then the spacing unit map isavailable for review by contacting the appropriateDivision of Mineral Resources regional mineralsmanager for oil and gas.”See Gas Lease questions on the DEC website athttp://www.dec.ny.gov/

Q:Does a lease give the well operatorthe right to “trespass” on my land?

A: Under a lease agreement the lessee does have animplied easement to use the surface of the land asmay be reasonably necessary to obtain produc-tion. This will be true unless the lease has specificprovisions against surface entry. This type of leaseis known as a “non-surface entry lease.” If con-cerns exist about specific surface disturbancesyou should negotiate appropriate protectivemeasures into the lease agreement. For example,express lease provisions could address the loca-tion of access roads, the proximity of pipelines orwells to structures on the property or sites offuture buildings, and can place responsibility forsurface damages on the lessee. See Gas Leasequestions on the DEC website at http://www.dec.ny.gov/

Q:Is there a standard royalty percentagefor natural gas leases in New York?

A: There is no set standard royalty percentage asmarket forces control the royalty rates. However,integration hearings before the Division of MineralResources show that “all thirteen companieswhich have drilled wells subject to integration inNew York have leased for a 1/8th (12.5%) royalty.”See Gas Lease questions on the DEC website athttp://www.dec.ny.gov/


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Q:How do you get the best price in alease?

A: NumbersConsider negotiating a lease as a group with otherlandowners. This will increase your bargainingpower. It will also be appealing to the businessbecause they can save costs by negotiating onecontract instead of many and they can securelarger tracts of land with one effort.

There have been several successful efforts by localland owners to band together to form negotiatinggroups. These appear to have been successful andhave often been able to bring together significantnumbers of property owners who collectively havebeen able to obtain expert and legal counsel toassist in their negotiations. For example, “in lateJuly 2008 a group of property owners in theDeposit area signed over about 10,000 more acresto XTO Energy for mineral rights. According toreports in the Binghamton Press, to date, thecompany is paying $110 million in lump sums tomore than 500 property owners in the towns ofSanford and Deposit for the right to drill on theirland. Meanwhile, thousands of property ownersacross the Southern Tier are following Deposit’slead by forming coalitions to maximize theirbargaining power. In Broome County alone, atleast 10 groups have formed with the potential ofleasing 200,000 acres or more. Groups also areorganizing in Tioga and Chenango counties, whilean untold number of individual property ownersbargain on their own.”http://www.steny.org/usr/observations%20on%20gas%20production%20on%20marcelus%20shale(REV).pdf

Keep your Options Open• Negotiation with more than one gas operator can

increase the value you receive for your land. Itcould lead to competitive bidding and as compa-nies bid against each other higher prices andmore favorable terms can result. Negotiation

• Negotiate the terms that will protect yourinterest. Communicate your goals to an attorneyand have them negotiate the terms for you. Thatway you can be sure that your interests areprotected from a legal standpoint.

Q:Can gas companies take gas fromunder your land if you do not sign alease?

A: No. If you land is within a spacing unit anddrilling takes place you will be required to chooseone of the compulsory integration options. Regard-less of the option you choose you will be paid aroyalty if gas is extracted and sold.

Q:Do the same terms mean the samething in every lease?

A: Terms relating to payments under the lease,length of the lease as well as others can be calcu-lated in different ways. For example, two leasesthat both provide for royalty payments of 1/8 maynonetheless be calculated in very different ways.Make sure you understand how the terms of yourlease are calculated. Ask questions and be sure toconsult an attorney to make sure what is writtendown reflects your understanding.

Q:What things should I considerbefore signing a lease?

A: Land disturbance from an access road and drillsite.The actual drilling of a well is a temporary activitythat may involve large amounts of equipmentsimilar to other construction projects. Be sure thatyou know how much of your land and which partsof it will be used for access, drilling, production,pipelines, compressors and short or long termstorage of equipment. Have mutually approvedreclamation plans incorporated into your lease.

Damage to crops, buildings, and other personalproperty.The lease can also be written to require fences orother safeguards if needed to protect people orlivestock. If not covered in the lease, considerasking for terms that make the company respon-sible for damage to crops, livestock, buildings andother personal property.

Free gas.Leases may provide for free natural gas for thelandowner’s use if a well is drilled on the pre-mises. If the lease does not specify that thecompany is responsible for the cost of equipmentand installation, then you may have to pay for it.Because of safety concerns, the company mayprovide for monetary payment in lieu of free gas asan alternative.


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Lease assignmentThe lease may contain a clause which allows thecompany to assign or sell the lease to other firms.

Underground Gas storageGas production reservoirs are ideally suited forunderground gas storage after the gas has beenproduced. The lease may contain a clause whichpermits gas storage in return for an annual rentalpayment.

Note: The above discussion was excerpted fromthe DEC website at http://www.dec.ny.gov/.While paraphrased slightly the direct quotationsfrom the source are omitted for readability pur-poses.

Q:What if there is a dispute with thedrilling company?

A: Most “standard leases” contain a provision thatrequires the use of arbitration to resolve disputesbetween the landowner and the gas company.Arbitration panels typically consist of threearbitrators. The landowner (lessor) and company(lessee) each pay the fee for one arbitor and splitthe fee of the third.

Arbitrations can be very expensive. In some casesyou may be required to pay the companies fees ifthe arbitrators decide against you.

Q:What if I want to sell my land?A: Entering into a gas lease means that you are

granting a right to others which may be viewed asan encumbrance on your property.

Q:What if I want out of the lease?A: You have the right to cancel for three business

days after signing the least. There are certainprocedural requirements for doing so. You shouldconsult an attorney to make sure that they areproperly followed.

Consequences after three days:Canceling after three days can give the businessthe right to pursue damages against you in court.The amount of money you may have to pay can besubstantial. Consult an attorney so that you fullyunderstand your liability before doing so.

Compulsory Integration Questions:*Note: if you have signed a lease then the Compul-sory Integration process does not apply to you.Please see “Gas Lease Questions” section above forlease related questions.

• The first set of questions address the regulatoryprocess of how spacing units are assigned, thepermit process and general timetable of action.

• The second set of questions clarify who issubject to spacing units and differentiatesbetween leased lands and those who are madeparties to the spacing unit through the compul-sory integration process.

• The third set of questions go to the optionsavailable to unleased portions of land within aspacing unit. (note: leased lands are not subjectto compulsory integration).

Q:What are “pooling” and “compulsoryintegration”?

A: “If your acreage is in the spacing unit and youdon’t lease, then your rights will be addressed bythe compulsory integration process. If gas is soldfrom the well in the unit and you elect to beintegrated as an “Integrated Royalty Owner,” thenyou will receive a royalty for production. The welloperator must pay Integrated Royalty Ownerspromptly and no less frequently than it pays itslessors. Assuming the integration order is issuedprior to first product sales, royalties will be paidupon commencement of production. If you lease toanother company (other than the operator) whoparticipates in the well, then you would be paid byyour lessee from the commencement of productionif that is what your lease requires.”See Gas Lease questions on the DEC website athttp://www.dec.ny.gov/

Q:When will land be subject tocompulsory integration? Should alandowner sign a lease or wait?

A: There is no compulsory integration process unlessthe DEC issues a permit to drill and the land isincluded in a spacing unit. Historically, “only 10-15% of the acreage leased by oil and gas compa-nies is ever included in spacing units, and theDepartment cannot issue a permit to drill unlessthe applicant controls 60% of the acreage in aspacing unit. If everyone in a prospective areawaits for compulsory integration, it will neverhappen because no well will be drilled.” See GasLease questions on the DEC website at http://www.dec.ny.gov/


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Only you can determine for yourself, with appro-priate legal advice, how the compensation offeredfor a lease on your acreage stacks up against anyperceived disadvantages.

Q:Can you give a brief overview of thespacing unit and compulsoryintegration process?

A: As of August 2, 2005, an applicant for a permit todrill an oil or gas well in New York State mustinclude, in the permit application, a map showingthe area that will be assigned to the well. Thisarea, called a spacing unit, may include some orall of your acreage even if you haven’t signed anoil and gas lease. After the Department of Environ-mental Conservation (DEC) issues a well permit,you will be required to elect an option for how yourunleased acreage in the spacing unit will beintegrated with other properties in the unit. Yourelection will be finalized by issuance of a compul-sory integration order after a public hearing. Thisprocess consolidates control and management ofwell operations with the well operator who holdsthe permit from DEC. If you have leased your oiland gas rights to someone else, then you are notrequired to make an election; your lessee willmake the decision if necessary.

Each option presents different risks and potentialrewards. The option you select may subject you tocertain costs and obligations, and there is noguarantee that a well will make money. Youshould carefully consider all the implications ofyour decision. If no permit is issued, then youracreage will not be affected.

The above discussion was excerpted from the DECwebsite at http://www.dec.ny.gov/. While para-phrased slightly the direct quotations from thesource are omitted for readability purposes

Q:What should a landowner expect tohappen before a hearing if the DECissues a well permit based on aspacing unit that includes thelandowners unleased tract?

A: The following procedure is an outline exceptedfrom the DEC website:1.The DEC will assign a hearing date when the

permit is issued.

2.At least 30 days before the hearing, the welloperator will send a notice directly to you. It willinclude the following:- Date, time and place of hearing- Proportion of your acreage to total acreage in

spacing unit- Estimated well costs, including plugging costs- Election form for choosing your integration

option- Draft integration order

3.You will have 21 days after receiving the form tomake your election.

4.If you elect to be an “Integrated ParticipatingOwner,” payment for your share of the estimatedwell costs is due to the well operator by thehearing date.

After you receive the hearing notice and before theintegration hearing, you still may enter into alease or other private agreement regarding devel-opment of your oil and gas rights. If you establishan agreement with someone other than the welloperator, you should provide the notice package tothat person or company immediately.

Compulsory integration hearings are held inAlbany, New York, on a regular schedule. Seehttp://www.dec.ny.gov/

Q:Are there any options beside thecompulsory integration process orsigning an individual lease?

A: Joint Operating Agreements are “common in theoil and gas industry.” The DEC cannot requirethem but does “strongly encourages these agree-ments between the well operator and other poten-tial working interests within the spacing unit.” Theadvantage of these agreements is that businessdecisions such as “data sharing, payment sched-ules and audits” are controlled by contract insteadof state government.

Q:What are the different compulsoryintegration options?

A: If your acreage remains unleased but it is in aspacing unit, you must choose one of the follow-ing:– Integration as a royalty owner– Integration as a non-participating owner– Integration as a participating owner


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In what way do they differ?• Costs• Liabilities• Rights to payment• Temporally, when payments and costs are owed

or due.

Q:When will the compulsory integrationoption choice be made?

A: In most cases, you will be making this choicebefore the well is drilled and “before you knowwhether the well will be a success that pays foritself, a marginal producer that never pays foritself, or a dry hole. Even if a well initially pro-duces hydrocarbons, it is impossible to know inadvance whether it will continue to produce formany years or for a very short time, such as amonth or less. It is certain that the amount of oilor gas a well produces will decrease over time. Therate of decrease is another factor that cannot bepredicted.”See http://www.dec.ny.gov/

Q:What is a production unit?A: It is a collection of land that is believed to contrib-

ute gas to a well from underground reservoirs.Although these areas range in size they aretypically around 640 acres.http://www.steny.org/usr/observations%20on%20gas%20production%20on%20marcelus%20shale(REV).pdf

Q:How are royalties divided amongowners of a production unit?

A: The amount paid to “eligible property owners” isbased on their “ownership share of the productionunit.”http://www.steny.org/usr/observations%20on%20gas%20production%20on%20marcelus%20shale(REV).pdf

Q:What can landowners do to increasetheir return from the well?

A: They can form groups and negotiate collectively:The Binghamton Press reports that one collectivebargaining group leased mineral rights in over10,000 acres to a gas company. The company isreportedly paying over $110 Million to approxi-mately 500 landowners.See Binghamton Press and Sun Bulletin, August3, 2008

Q:If I do not lease to the well operator,will I not receive any compensationbecause my acreage will beexcluded from the unit?

A: No. A landowner within a spacing unit mustchoose one of the compulsory integration optionsand cannot elect to abstain from the drillingprocess.

Q:What does it mean to elect integrationas a Royalty Owner? Process/Costs/Benefits/Liabilities

A: Costs - If you elect this option, you are not liablefor any charges or fees associated with welloperation. A dry hole costs you nothing. This isthe default option if you do not make a selection.

Compensation - If the well produces, the welloperator will begin paying you a royalty shortlyafter production starts. The royalty will be no lessthan one-eighth of the revenue received by the welloperator for the share of production attributable toyour acreage. An integration order is not a “forcedlease” and will not award you a signing bonus.

Q:What does it mean to elect integrationas a Non-Participating Owner?Process/Costs/Benefits/Liabilities

A: Costs - If you elect this option, you will have thesame responsibilities as a Participating Owner,but you do not risk your own money by payingyour share of costs up front. A dry hole costs younothing.

Compensation - You will not receive any compen-sation from the well operator, not even a royalty,until the well operator has, through the sale ofyour share of production, recovered your share ofthe costs plus a “risk penalty” of 200% of yourshare of costs, for a total of 300%. This meansthat the well must pay for itself three times beforeyou are compensated. After the well pays for itselfthree times, or if you buy out of the risk-penaltyphase by making a payment, you will receive yourshare of production and be treated as a Participat-ing Owner.

If you have leased to someone other than the welloperator, then your lessee may owe you a royaltyduring the risk-penalty phase. This is determinedby your lease, and the well operator has noobligation to you.


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If your lessee elects to be integrated as a non-participating owner, then the well operator mustmake royalty payments to your lessee during therisk penalty phase. These payments will be on agraduated scale from 1/16 up to 1/8, based onthe percentage of the lessee’s costs that have beenrecovered through sale of production.

After recovery of the risk-penalty, Integrated Non-Participating Owners are treated the same wayand have the same obligations as IntegratedParticipating Owners.

Non-Participating owners may bear liability forthird-party claims.

Q:What does it mean to elect integrationas a Participating Owner? Process/Costs/Benefits/Liabilities

A: Costs - If you elect this option, you must pay yourshare of estimated well costs by the time of theintegration hearing. This money will not berefunded if the well is a dry hole or does not payfor itself.

Compensation- You will receive your full share ofproduction. However, the well operator will have alien on your share of production to pay anyoutstanding amounts that you owe.

Responsibilities of Integrated Participating and Non-Participating OwnersA decision to be integrated as a participating ornon-participating owner subjects you to obliga-tions that do not enter the picture if you elect tobe integrated as a royalty owner. Some of theadditional considerations are as follows:• Actual well costs. The actual cost to drill or plug

the well may exceed the estimate that wasprovided before the hearing. You will be heldliable for your share of the additional costs.

• Completion and operating costs. If the well issuccessful, it will cost money to complete andoperate. You will be liable for your share of thesecosts for the life of the well.

• Gathering line costs. If the well is a pro-ducer, the well operator will provide youwith the estimated costs to install a gather-ing line to bring the gas to market. You willhave the option of paying your share upfront or having your share plus 100%withheld from your share of productionproceeds.

• Subsequent operations. The law defines certainoperations in the spacing unit, including addi-tional work on the existing well or drilling ofanother well, when you again must decide toeither pay up front or be subject to a riskpenalty. Subsequent operations may cost asmuch as or more than the original drilling.

• Other liabilities. As an integrated participating ornon-participating owner, you are liable for yourproportionate share of taxes and third-partyclaims related to drilling and operation of thewell.

Integrated Participating Owners are responsiblefor their share of costs for the life of the well.There may be time periods where costs exceedproduction so that money will be due to the welloperator. Drilling problems may increase costsabove the original estimate, or inflation maycause plugging costs to increase above originalestimates.

Participating owners may bear liability for third-party claims.

Note: The above discussion about the Process/Costs/Benefits/Liabilities of each compulsoryintegration process are excerpted directly (withminor reworking for readability) from the DECwebpage on “Compulsory Integration.” Quotationmarks are omitted. The material is available athttp://www.dec.ny.gov/

Q:Does the compulsory integrationprocess give the well operator theright to “trespass” on my land?Does the DEC integration ordergive them this right?

A: DEC’s integration order will not give the welloperator the right to enter your property.

Q:Can extracted gas ever remain onthe property?

A: No. However, certain leases provide for the gascompany to store gas underground. Such leaseswill provide for this expressly and usually thelandowner is compensated for this.


Appendix B:Eminent Domain

Q:How does one establish a “taking”under New York law?

A: To determine whether a mineral rights owner canbe awarded just compensation for a taking ofmineral property, the legitimate public interestserved by environmental land use restrictionsmust be balanced against the equally legitimateproperty rights of the mineral rights owner. TheNew York Court of Appeals has interpreted thisbalance to mean that a taking has occurred “onlyif the property is rendered unsuitable for anyreasonable income producing or private use forwhich it is adapted, and thus its economic value,or all but a bare residue of its value, is destroyed.”www.dec.ny.gov/docs/materials_minerals_pdf/fgeistopres.pdf

Q:What evidence must be shown toestablish a taking?

A: (1) The monetary value of the property under itscurrent use and the value of the propertyunder its permitted use.

(2) It must be shown that a permit was appliedfor and denied.

(3) It must be demonstrated that the effect of thedenial is to prevent economically viable use ofthe land, and

(4) It must be shown that the mineral rights wereacquired before the regulations that limit theproperty use.

The courts will hear a takings claim only if “dollarsand cents” value loss can be shown and thatadministrative avenues for addressing the issuehave been resolved. The mineral owner must alsodemonstrate that the prohibited use would nothave a negative or conflict-creating effect on theprotected land.www.dec.ny.gov/docs/materials_minerals_pdf/fgeistopres.pdf (quotation marks omitted)

Q:What can a mineral rights owner doif a permit is not granted and theycannot establish a taking?

A: Regulations and/or permit conditions restrictingwell locations rarely eliminate all drilling options.As such, it is likely still possible to “utilize ad-vanced drilling techniques such as directionaldrilling” to access the gas. It should be notedhowever that these techniques come at a cost andmany can be cost prohibitive if a large gas reserveis not anticipated.www.dec.ny.gov/docs/materials_minerals_pdf/fgeistopres.pdf

Q:What entities may exercise eminentdomain in New York?

A: The following is a very helpful discussion oneminent domain in the State of New York. It istaken from a New York practice digest available onWestlaw (see hyperlink at the end). The originalfootnotes are left in place - the relevant parts ofwhich are attached - so that the legal authoritycan be cited to.

The right of eminent domain is not inherent in anyprivate corporation, but the power of eminentdomain has been expressly vested by the legisla-ture in various private corporations, including gascorporations and pipeline corporations.[FN1]

A gas corporation has power and authority toacquire real estate necessary for its corporatepurpose by condemnation,[FN2] including a right-of-way for its pipeline through the property ofothers, once the public service department hasmade findings that the proposed pipeline isconvenient and necessary for the publicservice.[FN3] Also, if it holds a certificate of publicconvenience and necessity, a natural gas company

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which is subject to the regulatory jurisdiction ofthe Federal Power Commission, may, by theexercise of the power of eminent domain, acquirenecessary pipeline rights of way, and in additionthereto, the land it requires for compressorstations, pressure apparatus, or other equipmentincident to the operation of such a pipeline, if itcannot acquire such land by contract or is unableto agree with the owner on the amount of compen-sation therefor.[FN4] The right of such a companyto condemn a pipeline right-of-way has beenrecognized as absolute, whether the pipeline isintended for the transportation of gas across thestate for sale in another state,[FN5] or to delivergas from an out-of-state source to points withinthe state.[FN6]

Where a foreign corporation meeting the definitionof a natural gas company complies with theprovisions of the Natural Gas Act, its right toacquire by eminent domain a necessary andreasonable route across private property withinthe state may not be denied because the corpora-tion has not complied with the procedural require-ments prescribed by the Transportation Corpora-tions Law.[FN7]

A corporation empowered to produce, transport,distribute, or store gas within the state for ulti-mate public use, and which holds an undergroundstorage permit, or which is otherwise lawfullyoperating an underground storage reservoir, andwhich, after reasonable effort, is unable to obtainrights in real property and wells necessary foractivation, operation, or protection of such reser-voir, is empowered to acquire such rights bycondemnation, subject to certain restrictionsimposed by the statute.[FN8]

[FN1] N.Y. Jur. 2d, Eminent Domain § 15.As to condemnation of a right-of-way by a pipelinecorporation, see § 84.

FN2] N.Y. Transp. Corp. Law § 11(3-a).

[FN3] Home Gas Co. v. Eckerson, 197 Misc. 793,94 N.Y.S.2d 221 (County Ct. 1950), holding that acorporation organized as a private businesscorporation before the enactment of the Transpor-tation Corporations Law, for the purpose ofsupplying gas for public use by acquiring and

selling gas at wholesale to public utilities, was aTransportation Corporations Law gas corporationand had the right to acquire rights of way byeminent domain, since it was clothed with a publicinterest and the laying of its pipeline was a publicnecessity even though it was engaged in a privatebusiness.

[FN4] 15 U.S.C.A. § 717f(h), which also hasprovisions permitting the institution of condemna-tion proceedings in federal or state courts, andrequiring conformity as close as possible to statepractice and procedure if the proceeding isbrought in a federal court.As to federal regulation of pipelines, see § 68.

[FN5] Tennessee Gas Transmission Co. v.Schmidt, 108 N.Y.S.2d 435 (Sup 1951).

[FN6] Home Gas Co. v. Eckerson, 197 Misc. 793,94 N.Y.S.2d 221 (County Ct. 1950).

[FN7] Tennessee Gas Transmission Co. v.Schmidt, 108 N.Y.S.2d 435 (Sup 1951), involvinga gas pipeline and holding that a foreign corpora-tion was not barred from exercising the right totake property by eminent domain because it hadnot been organized in accordance with the statuteapplicable to pipeline corporations.

[FN8] N.Y. Envtl. Conserv. Law § 23-1303.As to permits for underground storage of gas orliquefied petroleum gas, see N.Y. Jur. 2d, Energy §153.

<http://web2.westlaw.com/result/documenttext.aspx?vr=2.0&rp=%2fTOC%2fdefault.wl&hiddenquery=Iac9ed43099ff11d8bae3d44e6a1fb9d3&sv=Split&cxt=DC&ifm=NotSet&fmqv=s&rlti=1&ss=CNT&rs=WLW8.11&eq=TOC&docaction=rank&db=NYJUR&cnt=DOC&fn=_top&n=10&scxt=WL&cfid=1&rlt=CLID_QRYRLT68267312920112&rltdb=CLID_DB74454302920112&origin=Search&mt=70&service=Search&query=%22NATURAL+GAS%22+%26+%22PIPE!%22&method=TOC>

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Q:Does the State of New York Stateprotect “correlative rights,” namelyan opportunity to receive the benefitsof oil or gas beneath your acreage?

A: “It is the policy of New York State to protect whatis known as your “correlative right” to an opportu-nity to receive the benefits of oil or gas beneathyour acreage. For unleased owners, this opportu-

nity is ensured by the compulsory integrationprocess. Before compulsory integration proceeds,the operator must attest to control of oil and gasrights on at least 60% of the acreage in a spacingunit. The spacing unit is established when DECissues the well permit. Compulsory integration isnecessary only if the well operator does not control100% of the spacing-unit acreage.” See http://www.dec.ny.gov/


Appendix C:Conflict Resolution

Introduction

The traditional response to conflict resolution inthe legal community has been litigation. Jacqueline M.Nolan-Haley, Alternative Dispute Resolution in aNutshell 1 (3d edition, 2008). However, there are otherproblem-solving approaches available through alterna-tive dispute resolution (ADR) that can help disputingparties achieve their goals. Id. at 1-2. “ADR is anumbrella term that refers generally to alternative tothe court adjudication of disputes such as negotiation,mediation, arbitration, mini-trial and summary jurytrial.” Id. at 2. These different forms of conflict resolu-tion offer creative solutions to problem solving thatmay better address a particular person’s needs thanlitigation. Litigation is not necessarily the one size fitsall solution to conflicts because it has its own draw-backs. For example, if disputing parties are in a long-

term relationship then litigation may not be the rightapproach to resolving their problems because it is acontentious process that may exacerbate the existingtensions in the relationship and contribute to itsdemise. Solving the problem through mediation mightbe a better idea because mediation emphasizesreaching a solution to the problem through a coopera-tive process seeking to identify the underlying commongoals and interests of the parties. In this context,mediation is likely to help repair or maintain therelationship between the parties.

Q:What is ADR?A: ADR stands for alternative dispute resolution.

ADR refers to alternative methods of conflictresolution besides litigation. Some common formsof ADR are mediation, arbitration and negotiation.

(More to come.)

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Appendix D:Guide to theGeohydrologyof the Area

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To be completed.


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Appendix E:Technical Resources

Albany County

Soil & Water Conservation DistrictBox 497, 24 Martin RoadVoorheesville, NY 12186Phone: (518) 765-7923Fax: (518) 765-2490Email: [email protected]

Allegany County

Soil & Water Conservation DistrictAg Service Center5425 County RT. 48Belmont, NY 14813-9758Phone: (585) 268-7831, Ext. 3Fax: (585) 268-7224Email: [email protected]

Broome County

Soil & Water Conservation District1163 Front StreetBinghamton, NY 13905Phone: (607) 724-9268Fax: (607) 723-1015Email: [email protected]

Cattaraugus County

Soil & Water Conservation District8 Martha Street, PO Box 1765Ellicottville, NY 14731Phone: (716) 699-2326/2327Fax: (716) 699-5506Email: [email protected]

Cayuga County

Soil & Water Conservation District 7413 County House RoadAuburn, NY 13021Phone: (315) 252-4171/0793Fax: (315) 252-1900Email: [email protected]

Chautauqua County

Soil & Water Conservation DistrictFrank W. Bratt Ag Center3542 Turner RoadJamestown, NY 14701-9605Phone: (716) 664-2355 Ext. 3Fax: (716) 483-0773Email: [email protected]

Chemung County

Soil & Water Conservation District851 Chemung St.Horseheads, NY 14845Phone: (607) 739-2009/4392Fax: (607) 739-4392Email: [email protected]

Chenango County

Soil & Water Conservation District99 North Broad StNorwich, NY 13815-1388Phone: (607) 334-4632/8634Fax: (607) 336-2918

(All NY State to be included - underway)


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Appendix F:Acryonyms andGlossary

AcronymsCWA: .............................................................................................................Clean Water ActCAA: .................................................................................................................. Clean Air ActDEC: ............................................................ NYS Department of Environmental ConservationDOT: ................................................................... United States Department of TransportationDPS: ........................................................................................ Department of Public ServicesDRBS: ................................................................................ Delaware River Basin CommissionDSGEIS: .................................. Draft Supplemental Generic Environmental Impact StatementEAF: ....................................................................................Environmental Assessment FormEIS: .................................................................................... Environmental Impact StatementEPA: ................................................................................... Environmental Protection AgencyFERC: ........................................................................ Federal Energy Regulatory CommissionFOIL: .......................................................................................... Freedom of Information LawFSGEIS: ................................... Final Supplemental Generic Environmental Impact StatementIMP: ........................................................................................ Integrity Management ProgramNOI: ................................................................................................................ Notice of IntentNORMS: ................................................................. Naturally Occurring Radioactive MaterialsNPDES: ........................................................National Pollutant Discharge Elimination SystemNRDC: ............................................................................. Natural Resources Defense CouncilOSHA: ............................................................ Occupational Safety and Health AdministrationPHMSA: ............................................. Pipeline and Hazardous Material Safety AdministrationPIPESA: ...................................... Pipeline Inspection, Protection, Enforcement and Safety ActPSC: ............................................................................................. Public Service CommissionSDWA: .............................................................................................. Safe Drinking Water ActSEQR: ....................................................................... State Environmental Quality Review ActSGEIS: ..............................................Supplemental Generic Environmental Impact StatementSPDES: ................................................................ ate Pollutant Discharge Elimination SystemSRBC: ......................................................................... Susquehanna River Basin CommissionUIC: ........................................................................................ Underground Injection ControlUSC: ........................................................................................ Upper Susquehanna Coalition

GlossaryAccess RoadsCompensationCompulsory IntegrationCompulsory Integration HearingsCondemnationCorrelative RightsDevonian Black ShaleDispute Arbitration


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Drill SitesEasementEminent DomainEnvironmental Assessment and Environmental Assessment FormGas LeaseGas reservoirsGathering linesHydrofrackingLandmenLease TermsMineral RightsNon-Participating OwnersPoolingPounds per square inch (PSI)Production UnitRighs-of-wayRoyaltiesService LinesShut-in RoyaltySpacing unitsSupplemental Generic Environmental Assessment StatementTakingsTerminationTransmission linesUnderground Gas StorageVacuum pumpsViewshedWater useWell casingsWell platformWell pluggingWell spacing


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Appendix G:References

Underway.


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Appendix H:Best ManagementPractices forGas Drilling

To be completed.

gas drilling guide - otsego county, new york

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