Commissioner Joseph Martens Department of Environmental Conservation 625 Broadway Albany, NY 12233-1011 July 25, 2011 Re: Draft SGEIS Comments Commissioner: Thank you for the fine progress that your Department has made on this draft. It represents a major improvement over the previous drafts and for that we are grateful. I was a planning manager at Atlantic Richfield and was an independent oil and gas investor for over 30 years, primarily in onshore and offshore drilling rigs. I hold an M.B.A. from the University of Pennsylvania Wharton School of Business (1976). My wife and I split our time between Cooperstown and Texas. There are some issues that I would encourage your Department and your Advisory Panel to look into: 1. 2. 3. 4. 5. 6. 7. 8. No place to dispose of raw or processed frack waste. The socio-economic study grossly overstates the benefits. The DEC does not have the resources to enforce the SGEIS guidelines. Disparate treatment of water sources based on population is inequitable. Permitting should be subject to local control. New York water sources are uniquely vulnerable to methane pollution. Compulsory pooling should not be applied to horizontal wells. Lack of coordination with other state agencies presents a serious problem.
1. There is no place in the state to safely dispose of frack waste. The lack of facilities to dispose of fracking wastes is emblematic of the State’s lack of preparedness for this activity. The DEC attempts to mask this lack of preparedness but does not require key shortcomings to be solved prior the issuance of permits. Proceeding without adequate preparation simply repeats the mistakes made in Pennsylvania. That state issued permits without any clear disposal plan in place for the frack waste generated. The results were shameful.1 The SGEIS lists various ideas of how to address frack waste disposal – but offers no conclusive solutions. There are only 6 permitted disposal wells in the state (compared to almost 12,000 in Texas), only 3 of which are open wells and none of which take frack flowback. Consequently, wholly irresponsible “solutions” have been deployed in New York – including spreading flowback as desalting material on roads and dumping it into municipal treatment plants.
The lack of proper disposal wells has become an acute problem in Pennsylvania, where flowback is trucked to the closest disposal wells in Ohio, or trucked to municipal treatment plants in New York that are not equipped to treat it, leaving many of them vulnerable under the proposed SGEIS. Fracking flowback is toxic and radioactive. The SGEIS equivocates on radioactivity. Shale is, by the American Petroleum Institute’s definition, more radioactive than any other sedimentary layer. If it were not, it would not show up as “shale” on the gamma ray reading of a well log. Horizontally hydrofracking shale is a textbook way to bring radioactive material to the surface, then process and recycle them, increasing their radioactivity to high levels. The proposed regulations mention re-use, but re-use is not disposal; it simply increases the net toxicity with each re-use. The proposal mentions treatment, but filtration will not remove all the toxic chemicals in solution, and thermal distillation is not economical. Applicants should be required to prove that the flowback material or treated sludge are lawfully disposed of. Tracking of waste is not sufficient. Tracking is not final disposition. Failing that, the flowback will be dumped on roads and in rivers as it has been in Pennsylvania, to that state’s disgrace; a practice now imitated in New York.2 Until an applicant can prove how they intend to dispose of the flow back (or the sludge removed from processing flowback), the DEC should not issue a drilling permit. Until other agencies, including ORPTS and NYSDOT are prepared to deal with the impacts of horizontal fracking, no permits should be issued. 2. Socio-economic Study Grossly Overstates Economic Benefits The socio-economic grossly overstates the benefits of horizontal hydrofracking because it grossly overstates the amount of recoverable reserves. In truth, the report does not show any reserve estimates used to determine the number of wells, flow rates, etc – a major flaw in the methodology. These reserve estimates should have been clearly stated along with their precise source. One can infer from the number of wells and their expected production that the study is based on the now discredited 2011 EIA estimates for recoverable reserves in the Marcellus, approximately 400 Trillion cubic feet, an estimate that was off by a factor of 5 according to the more recent and more precise USGS estimate of 80 Tcf for the total Marcellus in four states.3 The USGS report was not released until after the socio-economic study was completed. See Figure 1 below. The extent and productivity of shale gas development has been invariably overstated by
http://www.pittsburghlive.com/x/pittsburghtrib/business/s_753018.html#ixzz1Vx6eYW Bz 2
“pure play” shale gas companies.4 The first step is to exaggerate the productive area of the shale and the amount of recoverable reserves. This is what happened with the Socio-Economic study, which likely overstates jobs, etc. by a factor of 4. Fig. 1 Recoverable Reserve Estimates of the Marcellus Formation
QuickTimeª and a decompressor are needed to see this picture.
In most New York counties, HVHF exploration in the Marcellus will be a rankprospecting exercise - since the geological conditions that exist in border counties in Pennsylvania simply do not cross the border into New York. Bradford County, Pa. is near the maximum shale thickness, as shown below. The border counties to the west of Bradford are already proving marginal. 5 Three test wells indicate that the Utica and Marcellus may not be productive in Otsego County. While profitability is more than a function of shale thickness, the isopach gives us a first order indication of where to drill. The prospects for the Marcellus in New York have been consistently overstated - and this has led to grossly unrealistic expectations.6 We can quantify the environmental hazards better than we can forecast the economic upside, so
http://www.theoildrum.com/node/7075 http://articles.philly.com/2011-06-29/business/29717422_1_test-wells-marcellus-shaleproduction-rates 6 http://www.nytimes.com/2011/06/26/us/26gas.html?_r=1&emc=eta1
wildcat wells should be treated with an appropriate amount of caution – if allowed at all. Figure 2 shows what the Marcellus looks like to a geologist - the gross shale thickness in feet along the Pennsylvania / New York border. Fig. 2 Gross Thickness of the Marcellus in N. Pa./S. NY.
Exploratory wells are demonstrably speculative in nature and typically drilled by transient crews, not with local hires.7 Permitting wildcat wells in environmentally sensitive areas would not only be poor environmental stewardship, it would be bad geology. This is a fundamental flaw with the dSGEIS’s one-size-fits-all approach to well permitting. Shown below is what the Marcellus formation’s more productive Union Springs lens looks like. The shale is thickest in Bradford County. Areas outside the green would be classified as speculations, more often than not with negative impacts on local communities. Fig. 3 Union Springs Formation
The gross isopach of the Marcellus indicates that only a few border counties in New York are likely to qualify as being economically viable for shale gas exploration – Chemung, Tioga, Broome and Delaware. The rest, based on recent results in Pennsylvania, are probably marginal, so HVHF well applications should be treated as rank explorations both by the DEC and the local townships. 3. DEC is unable to adequately regulate the activity.
While we appreciate that the DEC will use its best efforts to maintain a high standard of oversight, the reality is that the DEC is not adequately staffed and funded for this task - as the former Director made clear before his departure. Nothing proposed has changed that situation; only the rhetoric is different. The DEC staff we have dealt with have been competent and dedicated individuals. But the Department is starved of funding – at a critical time. It cannot take care of the legacy problems it currently has, much less take on new ones.8 This is evidenced by the fact that the DEC does not have the funds to properly plug and abandon the thousands of orphaned wells that lie rusting away in the state.9 In that regard, applicants should be required to post bonds to cover the plugging and abandonment liabilities. Or these wells, too, will likely be orphaned and the funds set aside to plug them misspent. In order to fund regulatory activities, the State needs to implement a tax on production (a severance tax). Absent a clear source of funding, the DEC should refrain from issuing permits for HVHF wells. The DEC cannot afford to issue permits on wells that it cannot adequately regulate. Gas production is taxed at the wellhead in all gas-producing states, with the exceptions of Pennsylvania and New York. Pennsylvania does not even have a property tax on gas wells – making it the only place in the world that has neither a tax on production nor a tax on the value of the wells. The rate on gas production in Texas is 7.4%. In some countries, such as Mexico, it is effectively 100%, since the state owns the asset and the gas produced.10 The map below shows the states with a production tax. Fig. 4 Production Taxes by State
Production or “severance” tax revenues can add up – billions annually in Texas, New Mexico, and Louisiana. These revenues are typically used to pay for state regulation of the activity and as allocations to counties and school districts impacted by drilling. A summary of the amounts paid and the allocation of the revenue is given in a report
http://www.pressconnects.com/article/20110913/NEWS01/109130379/DEC-226-newworkers-needed-fracking-enforcement?odyssey=mod|newswell|text|FRONTPAGE|p 9 http://www.propublica.org/article/deteriorating-oil-and-gas-wells-threaten-drinkingwater-homes-across-the-co 10 http://www.mineralweb.com/owners-guide/leased-and-producing/royalty-taxes/gasseverance-tax/
prepared by the National Conference of State Legislatures.11 A map showing how production taxes are allocated is shown in the following map. If there is no tax at the wellhead, the state will not be able to adequately monitor production – nor will it even routinely inspect the wells. Absent such monitoring, the state will not be able to verify the production that is self-reported for purposes of ad valorem (property) tax on the wells. So the valuation of wells on the tax rolls will be suspect. New York’s ad valorem tax methodologies, as promulgated by ORPTS, are in need of being updated, since they will fail to capture the hyperbolic declines of horizontally fracked shale gas wells. 12 Fig. 5 Allocation of Tax Revenue
Lobbying against a severance tax in New York would be disingenuous for almost all the companies that have leased mineral rights in the state. The question should be not whether there should be a production tax, but what the rate should be. The rate imposed in the company’s home state should be the starting point. If the lobbyist represented Chesapeake, headquartered in Oklahoma, that answer should be 7%.13 If the lobbyist represented Range Resources, Cabot or XTO, headquartered in Texas - the answer should be 7.4%.14
http://www.ncsl.org/default.aspx?tabid=12674 http://my.brainshark.com/Tax-Frackonomics-962209960 13 http://www.tax.ok.gov/gp2.html 14 http://www.window.state.tx.us/taxinfo/nat_gas/ 6
The lobbyist may represent a foreign company – from say Norway, where the state has a direct interest in offshore production - and onshore horizontal hydrofracking is prohibited. Or from Quebec, where horizontal hydrofracking of shale is prohibited. The correct answer is not zero. The rate in most states is often on a sliding scale – tied to the price of gas, or the type of production – primary, secondary recovery, etc. Zero is the only wrong answer. A severance tax is one of the funding sources available to the State to partially offset damage done by drilling activities. The environmental damage from setback likely to be experienced in New York is considerably greater than has been seen in Texas.15 The cost of regulating the industry and repairing roads and bridges should be recouped by a production tax. As a very rough estimate of what this might equate to in New York – take the 1600 wells per year that the DEC projects will come online. That would equate to 1600 X 200,000 mcf/year X $4 per mcf = $1.28 billion, gross, times the 7% Texas/ Oklahoma rate = $89,600,000 a year for enforcement, road and bridge repair, and clean up associated with those wells. We know that many of those wells will be “dry holes” – not economic and not hooked up – generating no tax at all. The damage to roads and bridges would occur before the wells are tied in – and taxed. Road repair costs alone could absorb much of the production tax, as estimated by NYS DOT: “The annual costs to undertake these transportation projects are estimated to range from $90 to $156 million for State roads and from $121-$222 million for local roads.” There is no revenue offset, since NYSDOT cannot charge user fees to frack truck convoys, and most counties have no road use permitting systems in place.16 A severance tax may be the only tax a producer pays to the state. Most gas wells are owned as separate limited liability partnerships (LLPs or LTDs) or limited liability companies (LLCs). This is often done in an attempt to limit liability for damages to the well itself and its “shell company” ownership. However, it also means that any income derived from the well will be paid at the lower New York LTD or LLC rate, not the higher New York corporate tax rate. Since no major shale gas companies are domiciled in New York, it is unlikely that out-of-state gas companies will pay significant New York corporate taxes. Most will seek to reduce their New York state tax obligations through various avoidance strategies. Most of the cost of the well and most of the revenue associated with gas wells will leave the state either lightly taxed – at the LLC rate or untaxed.17 The only tax that a producer is unable to reduce or avoid is a production tax – provided there is one. The absence of one in New York is an indication that the industry has already begun to engage in tax avoidance at the top level.
http://my.brainshark.com/Horizontal-Hydrofracking-of-Shale-Gas-in-New-York162908032 16 http://my.brainshark.com/Frack-Truck-Convoys-By-Chip-Northrup-142091865
An ad valorem tax does not benefit State agencies. Most oil and gas states – except Pennsylvania – have a property tax on oil and gas wells – in addition to a production tax. So the fact that New York has a local ad valorem property tax on gas wells is no reason not to have a production tax paid to the state. The argument that that the property tax is “better than a production tax because it is local” is specious – since a gas well is a taxable asset – subject to a property tax like any other business asset, meaning it should be taxed - even in the absence of a production tax – as it already is in New York. In short, a property tax is a given, not an alternative to a production tax. The property tax valuation method used in New York state on gas wells is rather crude, so it may fail to fully capture the value of a horizontal shale gas well, one of the most difficult types of gas wells to value. ORPTS has not prepared a valuation methodology for horizontal shale gas wells. Local appraisers are not prepared. The DEC should not issue permits until counties and towns are ready to appraise them for property tax purposes. Like almost all states with oil and gas production, with the ignoble exception of Pennsylvania, New York has a property tax on gas wells.18 Like other property taxes, the beneficiaries are the counties, townships and school districts where the gas is produced. The appraisal methodology is administered by the Office of Real Property Tax Services (ORPTS), and is similar to that used in Texas.19 The appraised value is based on the income stream expected from the well – in Texas, the “discounted cash flow:”20 ORPTS attempts to summarize the value in a Unit Production Value (UPV) as a multiplier of the gas produced. Both methodologies are dependent on valuing the income based on the production history. In a conventional gas well with a relatively flat decline curve, estimating its value can be done more precisely. In a horizontally hydrofracked shale gas well, the rapid decline of the well’s production makes valuation problematic.
Fig 6. Decline Curves of Major Shale Gas Formations
http://www.orps.state.ny.us/sas/oil_gas/overview.htm http://www.tad.org/ftp_data/DataFiles/MineralInterestAppraisal.pdf http://en.wikipedia.org/wiki/Discounted_cash_flow
The first year’s production can account for up to 75% of the total production of the well. In New York, the gas production is self–reported by the producer. It is not clear that the ORPTS or the DEC has the staff necessary to actually verify these numbers in the field. Those production reports are in turn given to the local county and the township assessors who are responsible for doing the appraisals. Any lag - from the self-reported numbers to the report from ORPTS to the local appraisers – will delay the appraisal process. The ORPTS has yet to establish a UPV valuation for horizontally hydrofracked shale gas wells. Ironically, this is not how gas producers value their properties. Gas reserves are valued by the companies for their shareholders under Securities and Exchange Commission (SEC) rules. A valuation is made based on proven developed (producing wells), and proven undeveloped reserves – meaning the value of the gas in the ground, including gas that has not been drilled for. Banks give loans based on similar valuations. Yet the property tax valuation represents a fraction of the total value of the gas, since it is only valuing gas from producing wells. The ORPTs should establish a valuation method for horizontally fracked shale gas wells based on advice from oil and gas appraisal firms. Such firms are routinely hired by taxing authorities to do complicated appraisals.21 The ORPTS should review its procedures from the way it secures and verifies production data to the time the local appraisal is made and taxes are collected. Some wells will not produce. Drilling will negatively impact roads, bridges, water and air quality – regardless of the productivity of the well. The state should impose an impact fee to pay for some of these costs. As a practical matter, a severance tax is the only effective way that the value of a horizontal shale gas well can be fully taxed – since the tax calculation starts as soon as the well begins producing and the valuation can be much more straightforward than the
UPV multiplier. New York needs to correct that shortcoming in its tax code prior to the issuance of any permits by the DEC. Production Taxes in Some Other States With Horizontal Drilling Arkansas High cost gas (deep shale) and new discovery gas are taxed at a lower rate of 1.5 percent for the first 36 and 24 months respectively. If operators have not recovered their investment on the well at the end of the phase-in period, they can file for an extension. Ninety-five percent of the severance tax revenue is dedicated to roads. The remaining 5 percent is deposited into the general fund. Texas For the first ten years or until cumulative value of the tax reduction equals 50 percent of the drilling and completion costs incurred for the well, high cost gas wells are eligible for a reduction of the 7.5 percent tax rate as follows: 7.5 percent – (7.5 percent x (Drilling and Completion Costs / 2x Median Costs). Texas dedicates its severance tax to schools. Montana For the first 12 months of qualifying production, there is a phase-in of working interest of .76 percent and non-working interest of 15.06 percent. Likewise, for all horizontally completed well production there is an 18-month phase-in of qualifying production of .76 percent for working interest and 15.06 percent of non-working interest. After 18 months, working interest increases to 9.26 percent. Montana dedicates its severance tax revenue to counties, local governments, conservation, reclamation, remediation, and schools. West Virginia West Virginia imposes 5 percent of the value of natural gas at the wellhead, plus 4.7 cents per 1,000 cubic feet (mcf) of natural gas extracted, or an estimated total tax burden of 5.79 percent. West Virginia dedicates its severance tax to counties, local governments, conservation, reclamation, remediation, and a portion also helps to fund their Medicaid program. There are many reasons why a production tax should be imposed in New York State. A production tax has not hindered oil and gas exploration in any other jurisdiction. Indeed, such taxes are in place in all the jurisdictions where the major gas companies that hope to drill in New York are domiciled. We will not speculate as to why a severance tax has not been introduced in New York. We do question the political wisdom of permitting horizontally hydrofracked wells without first implementing a tax on gas at the wellhead. Absent a clear method of funding the regulatory tasks, such as a state severance tax, no horizontal wells should be permitted. The Department simply does not have the
capability to regulate the onslaught of exploration. We would encourage your Department and the Comptroller’s Office to petition the Administration and Legislature for some assistance in this regard since we note that New York is one of the few places on the planet that does not tax gas at the wellhead. With no production tax, it seems very doubtful the DEC will have the funding to be able to do its job adequately - no funds for environmental remediation, no funds for state road repairs, no funds for counties that are negatively impacted by gas exploration, strapped with unfunded mandates and held to a 2% property tax cap.22 Absent sufficient funding for regulatory oversight, permitting exploratory horizontally hydrofracked wells would be willfully irresponsible. 4. Disparate treatment of water sources based on population served The proposed ban of drilling within the New York City watersheds creates a double standard that is without scientific merit. The notion that the simple filtration systems of municipal water plants offers the residents any protection from the wastes found in fracking fluids and flowback is transparently a politically expedient excuse.23 The amount of protections proposed are directly proportionate to the population affected. The more people affected, the greater the protections. The New York City reservoirs will be protected ostensibly because they have no sedimentation filters while rural water wells will be unprotected, even though they have no sedimentation filters. This clear inequity is confirmed by the addition in Section 3.2.5 of this latest draft of a temporary ban for “Primary Aquifers” - whose only distinguishing characteristic from “Principle Aquifers” is the greater population served. Next on the hierarchy of protection are lakes that serve municipalities (2,000’), followed by private wells (500’) and last, streams (150’). The correlation of gas well setback from drinking water to population served is inequitable and without scientific merit. All watersheds should be given the protections afforded New York City, or horizontally hydrofracked wells should not be allowed in any watershed. 5. Well permitting should be subject to local land use controls We applaud the Department’s recognition of the importance of local land-use controls in 188.8.131.52. Local control is the norm in most states, where it has proven effective, appropriate and has been upheld by the courts. Home rule needs to be clarified in New York. In order to be clear, the permit applicant should show some proof of conformance with local land use as a condition of permitting. A thoughtfully crafted land-use ordinance based on local conditions should be able to protect the health and safety of residents better than a generic approach. Oil and gas reserves have been successfully developed in many other states where home rule is the law. The DEC’s SGEIS can guide development in un-zoned areas. The DEC should not preempt local land-use ordinances. Evolved state, county and city regulations in other states can serve as models for New York. Categories of State and Local Control
http://my.brainshark.com/Frackonomics-In-New-York-By-Chip-Northrup-900192077 http://184.108.40.206/documents/10sep21_McIntyre-DrinkingWaterinWatersheds.pdf 11
Most states combine state and local control, where the state minerals management agency issues the permits subject to some local controls. The question of preemption has either been settled by custom, typically where the state defers to the municipalities, by state law, or by the courts. New York is in a position to settle this matter by clarifying its Home Rule law as it pertains to well permitting. It should do so prior to permitting any horizontal shale gas wells. Local Ordinances Control Industrialization Most states, like California and Texas, share control over oil and gas drilling locations with municipalities by default. This means local land-use ordinances can control (or prohibit) drilling locations, and the state does not engage in generic land-use planning for well sites, like the SGEIS. State Preempts Local Control Some states, notably Ohio, specifically preempt local control on well siting, but offer no state-wide plan, as the SGEIS is designed to do. State and Local Ordinances Share Control Colorado’s state agency does land-use reviews for oil and gas development – similar to SEQR - but includes local authorities in that process and defers to recognized local authorities on well locations or prohibitions. Once Home Rule is clarified, New York’s procedures might be closest to Colorado’s. Zoning is not incompatible with responsible gas production The oil and gas industry pays billions in taxes directly to the State of Texas in the form of a production tax, and billions more in property taxes to the local municipalities and school districts. The majority of counties in Texas produce oil or gas in some quantities. All this has been accomplished without sacrificing Home Rule. Texas municipalities have the right to regulate oil and gas drilling within their corporate limits. This is not uncommon in oil and gas producing states; it is the norm in Western states, including California, Texas, New Mexico and Colorado.24 Like New York, Texas is a “Home Rule” state, meaning a municipality has broad powers to protect the health, safety and welfare of its citizens. The police power to zone extends to oil and gas activities in Texas, with the exception of public pipelines, as noted below. This is evidenced in state law and is reflected in the zoning ordinances of Texas cities. For instance, the zoning ordinance of the City of Southlake, which is in the Barnett Shale area, specifically states25:
http://findarticles.com/p/articles/mi_qa5447/is_200404/ai_n21349136/? tag=content;col1 12
“The drilling and production of gas and/or oil within the city shall only be permitted by specific use permit in accordance with section 45 of the zoning ordinance. (Emphasis mine.) A separate specific use permit shall be required for each pad site, and shall apply to all wells permitted by such specific use permit on that pad site. All applications for a specific use permit shall be accompanied by an application fee in the amount set in the city's fee schedule. A site plan is required with the specific use permit application and must include all information required by sections 40 and 45 of the zoning ordinance.”26 Other Texas cities, such as Fort Worth, have similar ordinances regulating oil and gas drilling. Until 2009, Fort Worth restricted oil and gas drilling to its Heavy Industrial zoning districts; now drilling can be done by special use permit (SUP) in other districts. The important point is local zoning controls. This means a driller could (in theory) get a drilling permit from the state minerals management agency, the Texas Railroad Commission (TRC), and be unable to drill due to local zoning restrictions. As a practical matter, TRC will refer to the local zoning code first. The laws that give municipal governments their authority are found in the Texas Local Government Code.27 This code describes the different types of local governments and the authorities that they have. Its wording is antiquated (“tanneries, blacksmiths, tallow, slaughterhouses,” etc.) and does not specifically address natural gas drilling. In Texas, natural gas development has come to be treated like any other noxious, hazardous industrial activity, and is regulated as such. Most local drilling ordinances require a permit from the TRRC before applying for a permit by the municipality. As a practical matter, if applicants knew they were not going to get the permit from the municipality, they would not apply for it at the TRRC. There is long standing case law that supports local authority over drilling operations. In Texas, the municipality is allowed to permit and regulate drilling - with no exemptions under state law. Gas wells involve substantial permanent above-ground structures, including gas separation units that will be required by the DEC at each well site. They also require pipelines to each well. They are permanent industrial structures. In Texas, the only exception to municipal authority is for intrastate midstream pipeline companies, which are treated as quasi-utilities under state law. Pipeline companies are supposed to be independent of the operating companies (drillers); however, many operating companies have purchased or started pipeline companies. In Texas, the pipeline companies have been given significant authority, which includes above ground appurtenances such as compressors, treating, or metering stations. (See Texas Utilities
http://www.cityofsouthlake.com/gasdrillinginsouthlake/Tracking%20Drilling %20Cases.htm 26 http://www.cityofsouthlake.com/SiteContent/70/documents/Departments/PlanningDevS ervices/Gas/Article%20IV_Chapter%209_5.pdf 27 http://law.justia.com/codes/texas/2009/local-government-code/. 13
Code.28) This authority has been subject to legal constraints by Texas municipalities. Chesapeake entered into litigation against the city of Grand Prairie and the courts found that municipal governments could regulate noise and aesthetics on above ground appurtenances of pipelines. Municipalities can also require mapping of the pipelines. Regulatory Models For New York Unlike Texas and New York counties, counties in New Mexico and Colorado can control land use – and they do so over predominately rural areas. For instance, Santa Fe County’s regulations have comprehensively planned and limited drilling in certain areas of the county.29 The Santa Fe County plan addresses local features the way a township might in New York – slope, vegetation, soil conditions, land uses – at a level of detail that is impossible for the SGEIS, but that would be of critical importance at the local level.30 In most oil and gas states, the task of addressing local land-use conditions is left up to municipalities (Texas and Kansas) or to both counties and municipalities (New Mexico and Colorado). Most states do not attempt to do “industrial land-use planning” similar to the DEC’s proposed SGEIS. One exception is Colorado – whose oil and gas regulations are comparable to the SGEIS or, in some counties an area-wide SEQR – taking into consideration local conditions - slope, vegetation, land uses – in a comprehensive review.31 These Colorado state regulations are augmented by local ordinances in some counties.32 Since these Colorado county plans are generally for rural areas, like Santa Fe County, they could serve as precedents for rural Upstate township land-use ordinances. The Colorado model might be applicable to New York, since in areas where there is no gas industrialization ordinances, the SGEIS would control. In areas where there are town or city ordinances that address gas industrialization, the local ordinances would control. The Colorado procedures, similar to a SEQR process, augmented with local ordinances would be an appropriate model for New York to consider. As applied in New York, the process would be as follows: 1. The driller shows that the well conforms to both the SGEIS and to local ordinances (or absence thereof) in their application to the DEC. 2. If it conforms to both, the DEC issues the well permit and the well is drilled. 3. If it does not comply with the SGEIS, the application is denied. 4. If it conforms to the SGEIS but does not conform to local ordinances, the DEC refers the applicant back to the local authority.
http://law.justia.com/codes/texas/2005/ut/003.00.000121.00.html http://www.santafecounty.org/county_attorney/oilandgas 30 http://www.santafecounty.org/userfiles/file/oilandgas/OilGasElement093008.pdf 31 http://cogcc.state.co.us/
Applied to well permitting, the New York mining law would track existing practice and save the applicant the trouble of getting a drilling permit from the state prior to subsequent review by the municipality. The DEC is removed from the position of having to opine on local land-use laws, but defers to them in its permitting process. As currently proposed, the DEC has set itself up to adjudicate the applicability of local land use laws, using its “one-size-fits-few” SGEIS approach as the benchmark – which may not be appropriate to local conditions and may be unenforceable when confronted with a properly crafted zoning ordinance and a municipality’s presumptive right to exercise its police power to protect the health, safety and welfare of its citizens. Wells get drilled and taxes paid in Texas towns and Colorado counties that approve them. By the same token, some wells that would be harmful in those towns and counties do not get drilled based on local ordinances. A bureaucrat in Austin does not get the final say in Texas. In New York, where environmental conditions are demonstrably more delicate, and where the DEC’s proposed “one-size-fits-few” standard is blind to the nuances of local land use, final approval can be more precisely dealt with at the local level. 1. 2. 3. 4. Home Rule should apply to oil and gas drilling. The SGEIS should control in un-zoned areas. The state should look to Colorado as a model. Rural towns should look to Santa Fe County as a model.
6. New York surface and groundwater is uniquely vulnerable to being polluted by methane. Horizontal hydrofracking faces unique environmental challenges in New York. The potential for environmental damage, particularly to groundwater, is greater than in the West. Upstate water wells are uniquely vulnerable to contamination from the surface – since they tap groundwater. Western wells are less likely to become contaminated because they “mine” deep aquifers, many of which have no communication with groundwater, as shown in Fig. 7, with deep western aquifer wells on the right, and shallow Upstate groundwater wells in the middle. Fig. 7 Water Well Depth – New York water wells compared to Western wells
The contamination of well water is not a major issue in Texas cities with municipal water supplies; Texas municipal wells tap deep aquifers and are not prone to contamination from the surface. Yet, the DEC has invoked municipal zoning standards, notably from the City of Fort Worth, in crafting its proposed generic regulations. This implies, on the one hand, that what works within the corporate limits of Fort Worth is applicable to the entire state of New York, and, on the other, that the DEC has preemption over such local land use ordinances: “8.1.15. The Department’s exclusive authority to issue well permits supersedes local government authority relative to well siting.” In other words, what’s good enough for the City of Fort Worth is not good enough for the City of Binghamton – unless controlled by the DEC. Curiously, the DEC’s proposed testing setback from a water well matches Fort Worth’s zoning ordinance (which is not superseded by state law). There is no other justification on the draft SGEIS for the proposed 500-foot limit. New York is patterning a critical catch-all regulation on a city with municipal water services in a semi-arid region in Texas. Water Well Testing Preliminary Revised Draft SGEIS 2011, Page 8-58 “Of the jurisdictions surveyed, Colorado and the City of Fort Worth have water well testing requirements specifically directed at unconventional gas development within targeted regions. Fort Worth’s regulations pertain to Barnett Shale development, where horizontal drilling and horizontal hydraulic fracturing are performed, and address all fresh water wells within 500 feet of the surface location of the gas well.” There are obvious hydrological problems with this assertion. First, there are very few private water wells in Fort Worth - which is entirely served by municipal water lines – in accordance with state law. Of the few private water wells in the city limits (typically golf courses), none are shallow groundwater wells of the type found in rural New York. These Upstate groundwater wells are uniquely vulnerable to surface pollutants – from spills, etc. and from methane migration of gas drilling operations. Texas wells tap aquifers – not
groundwater. Accordingly, a 500-foot setback that might be appropriate in a municipality in a semi-arid part of Texas would be wholly inadequate for Upstate. Unlike Colorado, where drilling programs are reviewed as a group, the DEC focus on individual wells does not consider the cumulative impact of multiple wells over an extended time period.33 While the setbacks have increased from the first draft – from 50 feet from a municipal drinking water lake to 2,000 feet – they remain inadequate based on recent studies. There appears to be little rhyme or reason for some of the setbacks other than population density for setbacks from drinking water sources, as previously noted. Most proposed setbacks and standards are similarly arbitrary or politically motivated. For instance, the DEC proposes a setback for a gas well from an abandoned oil or gas well of 5,280 feet (one mile) - vs. the Ft. Worth City Zoning standard of 600 feet from a water well. 220.127.116.11 Distances “Distances to the following resources or cultural features will be required. Distance from the surface location of the proposed well to the surface location of any existing (oil or gas) well that is listed in the Department’s Oil & Gas Database or any other abandoned (oil or gas) well identified by property owners or tenants within … 1 mile (5,280 feet) of the proposed well location.” It is ironic to note that the one-mile setback proposed from an abandoned oil well is the farthest setback distance listed in the SGEIS – twice as far as proposed for a municipal drinking water lake, and farther than from a hospital, apartment building, organic farm or school – because none of those uses are identified in the SGEIS - which is effectively blind to local land use. Abandoned gas wells are apparently more “sacrosanct” to the Cuomo Administration than drinking water. There is some rationale for not fracking a well next to an orphaned well – if the frack hits the old well bore, it could easily force fluids up the well bore into the groundwater. However, the DEC goes out of its way to discount the probability of a frack doing the same thing to a naturally occurring vertical fault – which are afforded no consideration under the SGEIS. The Department acknowledges that methane is often mobilized by the drilling process into ground water, but disregards the fact that drinking water is rendered unpotable - as if that were a normal consequence. Poisoning people’s water wells is not acceptable. The 500-foot setback proposed from a water well, lifted in whole cloth from the Fort Worth Texas zoning ordinance, is considerably less than the distances observed for methane migration into ground water in recent studies. The proposed water well setback, like the one proposed for streams, is without empirical justification. This is particularly apparent when contrasted with the politically motivated protections proposed for the New York City reservoirs and for primary aquifers.34 Again, the DEC’s rationale is without
scientific merit. This is the DEC’s take on the recent study of methane contamination of shallow water wells by gas drilling operations: Preliminary Revised Draft SGEIS 2011, Page 4-41 “In April 2011 researchers from Duke University (Duke) released a report on the occurrence of methane contamination of drinking water associated with Marcellus and Utica Shale gas development. As part of their study, the authors analyzed groundwater from nine drinking water wells in the Genesee Group in Otsego County, New York for the presence of methane. Of the nine wells, Duke classified one well as being in an active gas extraction area (i.e. a gas well within 1 km of the water well), and the remaining eight in a non-active gas extraction area. The analysis showed minimal amounts of methane in this sample group, with concentrations significantly below the minimum methane action level (10 mg/L) to maintain the safety of structures and the public, as recommended by the U.S. Department of the Interior, Office of Surface Mining. The water well located in the active gas extraction area had 5 to 10 times less methane than the wells located in the inactive areas.” The DEC infers the safety of water wells from one data point out of sixty – which was one of a few outliers in the study. This is not just bad science, it’s bad statistics. (See Figure 8.) It is a complete and willful misinterpretation of the conclusions of the Duke study, which tested 60 wells, most of which were in Pennsylvania, where setback had taken place, and which clearly indicated that local water wells were highly likely to be contaminated by methane migration - and that the source of the methane was from the formations drilled (thermogenic), not from surface (biogenic) sources.35 “Methane concentrations were detected generally in 51 of 60 drinking-water wells (85%) across the region, regardless of gas industry operations, but concentrations were substantially higher closer to natural-gas wells (Fig. 3). Methane concentrations were 17-times higher on average (19.2 mg CH4 L-1) in shallow wells from active drilling and extraction areas than in wells from nonactive areas (1.1 mg L-1 on average; P < 0.05; Fig. 3 and Table 1). The average methane concentration in shallow groundwater in active drilling areas fell within the defined action level (10–28 mg L-1) for hazard mitigation recommended by the US Office of the Interior (13), and our maximum observed value of 64 mg L-1 is well above this hazard level (Fig. 3). The report, which was peer reviewed and published in Scientific American, went on to conclude: “Overall, the combined gas and formation-water results indicate that thermogenic gas from thermally mature organic matter of Middle Devonian and older depositional ages is
the most likely source of the high methane concentrations observed in the shallow water wells from active extraction sites.” This means there is a high likelihood of shallow water wells being polluted by methane from drilling – from as far away as a kilometer (approximately 3,280 feet.). As long as the DEC ignores the empirical evidence and invokes inappropriate standards from other locales, its assertion cannot be trusted. Until another objective peer reviewed study conclusively contradicts the Duke findings, that report’s conclusions should guide the DEC in crafting its setbacks. There is no empirical, peer reviewed study to the contrary – only anecdotes. Methane pollution of shallow water wells has not been a problem in Texas because there are very few ground water wells in the Barnett Shale area. The rare instances where such methane pollution has been observed, notably in Parker County west of Fort Worth – were from shallow water wells next to the Brazos River. 36These exceptions prove the rule. Shallow water wells get gassed by gas well drilling. A lot. Drilling can mobilize methane which can pollute groundwater. Drilling can also pollute groundwater with drilling fluids. Upstate water wells are uniquely vulnerable to being polluted by drilling activities. None of the setbacks from surface water are adequate – 150 feet from streams, 2,000 feet from municipal drinking water lakes – no set-backs are proposed from private agricultural ponds or lakes, virtually assuring that many of them will be gassed with methane and polluted with drilling fluids. Fig. 8 Graph showing methane concentration (vertical) vs. distance
M th n c n e tra n (m ra s o C 4 e a e o c n tio s illig m f H Ê -1 a a fu c n o d ta c to th n a s g s w ll L ) s n tio f is n e e e re t a e fro a tiv (c s d c le ) a d n n c e (o e tria g s d m c e lo e irc s n o a tiv pn n le ) rillin a a . g re s
O b rn SGe a P A 2 1 ;1 8 1 2 1 6 so t l. N S 0 1 0 :8 7 -8 7
© 11 by N tion A de y o S 20 a al ca m f cien s ce
The 500-foot setback for water wells in New York is wholly inadequate. It would
virtually assure that many homeowners would have their wells gassed. There are no long term studies on the hazards of drinking methane-infused water – because it is not potable. Mobilization of methane from drilling is commonplace and has been known to be a problem by the industry for decades. Shown below is a graph that indicates in the gas wells studied, 40% of them were leaking by the 8th year. Figure 8 Sustained Casing Head Leaking of Gas Wells
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The mobilization of methane from the formation can be from a leaking production tubing or from channels in the outermost casing. Adding more casings, as proposed by the DEC
will not solve the problem if the methane is leaking outside the outermost casing, as shown below. Figure 9 Gas Leaking Outside Exterior Casing
QuickTimeª and a decompressor are needed to see this picture.
Poor Zonal Isolation
PRESSURE BUILDS UP
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SURFACE CASING QuickTimeª and a decompressor are needed to see this picture.
FRESH WATER AQUIFER ZONE
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SHALLOW PRODUCING ZONE
INTERMEDIATE PRODUCING ZONE
TARGET PRODUCING ZONE
7. Compulsory pooling should not be used on horizontal wells. Compulsory pooling was originally intended primarily as a safeguard – to prevent wells from being hazardously close and to optimize the recovery of the resource – all within the legal context of property rights. In this regard, compulsory pooling, as administered by your Department, should not be applied to horizontally hydrofracked wells – since such wells can effectively only “drain” adjacent property beyond the 40 acres around a vertical well bore by running laterals under them.37 Compulsory pooling should only be applicable to vertically fracked wells, and even there, it should be used sparingly, since the DEC has already demonstrated its willingness to compromise people’s health in the interest of making a well-spacing, a practice that is unheard of in Texas.38 The Attorney General should look into the constitutionality of applying compulsory pooling to horizontal wells. 39 8. Lack of coordination with other state agencies
http://my.brainshark.com/Why-Home-Rule-Matters-133909146 http://www.propublica.org/article/forced-pooling-when-landowners-cant-say-no-todrilling 39 http://my.brainshark.com/Compulsory-Pooling-of-Horizontal-Wells-134334393 21
Other state agencies are not prepared to deal with the impacts of shale. Most other functions critical to enforcement and revenue, are barely mentioned by the DEC, and some key agencies, such as ORPTS, are not mentioned at all in the SGEIS, leaving us to wonder whether ORPTS is involved at all at any level. 8.1.2 State “Except for the Public Service Commission relative to its role regarding pipelines and associated facilities (which will continue; see Section 18.104.22.168), no State agencies other than the Department are listed in GEIS Table 15.1. The New York State Departments of Health (DOH) and Transportation (DOT), along with the Office of Parks, Recreation and Historic Preservation are listed in Table 8.1 and will be involved as follows: • DOH: Potential future and ongoing involvement in review of NORM issues, and assistance to county health departments regarding water well investigations and complaints; (DOH conducted no health impact studies) • DOT: Not directly involved in well permit reviews, but has regulations regarding intrastate transportation of hazardous chemicals found in hydraulic fracturing additives; • OPRHP: In addition to continued review of well and access road locations in areas of potential historic and archeological significance, OPRHP will also review locations of related facilities such as surface impoundments and treatment plants.” This is a rather myopic view of the impact of the horizontal fracking of shale. For instance, the DEC has apparently not involved NYSDOT in the planning process. The number of large trucks necessary to complete a HHF shale well has been estimated at between 600 and 1,200 loads.40 Absent better protections from the state, municipalities, already under severe financial stresses, will be forced to deal with the negative impacts of trucking on their own. NYSDOT has evidently looked into this, and should be part of an inter-departmental review. NYSDOT has no funds to repair state roads damaged by frack truck convoys. No counties and few towns have road use ordinances in place to handle tens of thousands of heavy-use trucks required for fracking. Road and bridge damage costs for state and local roads range from, as taken from a recent report: “The potential transportation impacts are ominous. Assuming current gas drilling technology and a lower level of development than will be experienced in Pennsylvania the Marcellus region will see a peak year increase of up to 1.5 million heavy truck trips, and induced development may increase peak hour trips by 36,000 trips/hour. While this new traffic will be distributed around the Marcellus region, this Discussion Paper suggests that it will be necessary to reconstruct hundreds of miles of roads and scores of bridges and undertake safety and operational improvements in many areas: “The annual costs to undertake these transportation projects are estimated to range from $90 to $156 million for State roads and from $121-$222 million for local roads.
There is no mechanism in place allowing State and local governments to absorb these additional transportation costs without major impacts to other programs and other municipalities in the State.”41 At best, this indicates that the DEC is getting ahead of the State’s ability to deal with the impacts of setback, even to the detriment of other state agencies and the state’s infrastructure, much less to the detriment of local communities and the residents of the state. This lack of coordinated effort at the top appears amateurish. The results are predictable – state and county roads will be ruined, the state will have no funds to repair them, the DEC won’t have the resources to adequately regulate the activity and the environment of Upstate’s watersheds will be irreparably damaged. In conclusion, I would recommend the following broad objectives: 1. Until the Governor can demonstrate that the DEC is adequately funded to effectively regulate the activity and address the costs to the state of road repair and environmental remediation, no horizontal permits should be issued. 2. The SGEIS should be codified into regulations before permits are issued 3. Unless applicants can demonstrate and track final disposition of frack waste, they should not be issued a permit. 4. Set-backs from water sources should be based on science, not the Fort Worth, Texas zoning ordinance. 5. Safeguards should be uniform throughout the state and any differences should be based on science. Absent that, no permits should be issued that would jeopardize the health, safety and welfare of a majority of Upstate residents against their will. 6. Home rule should apply to well permitting - as is the norm in other states. We appreciate your efforts. I would encourage the DEC to proceed cautiously on these matters and to involve the Comptroller, DOH, NYSDOT and the Attorney General’s office in a collaborative process before the DEC considers issuing any permits for horizontal hydrofracking of shale gas wells.
James L Northrup 17 River Street Cooperstown, New York 13326