Sunday, October 13, 2013

MEC meeting reports Sept 27/13

WOW Diane has out done herself this time what a fabulous report !
grab a cup of coffee and give it a read ...

Notes from Mining & Energy Commission meeting September 27, 2013)
Chair, James Womack (Lee County Commissioner); Members Absent:  Charlotte Mitchell, Charles Taylor
Why EPA grant to test surface waters was refused; Frack wastewater disposal complex; No way to establish efficient gas-oil ratios with fracking; Who defines drilling units, industry or state?; Wellhead requirements rule approved; Setbacks, a very hot potato; Baseline testing for every water well within 5,000-ft....or just 2,000-ft...of gas well; Using tracers to spot contamination; Local Government Study Group report sent to Legislature; Compulsory Pooling Study Group report “tabled” in DENR; Funding Levels Study Group report sent to Legislature 
DENR Update on $222,000 EPA Grant, Tom Reeder, Director, Div. of Water Resources
Several articles in Raleigh News & Observer put DENR on the defensive to justify why they returned EPA money.  Chair Womack invited Tim Reeder to give “official” DENR response to MEC.  Reeder claimed (a) that the two-year grant was non-specific about components it would be testing, (b) surface water data collected does not have “shelf life” and the industry won’t arrive for several years, (c) grant didn’t precisely target the “exact” drilling area [an unknown], and (d) did not include groundwater [the study focused on surface waters].  The grant application was completed in March  2013 by the Div. of Water Quality, which no longer exists; and the section that wrote the grant has been eliminated.  He said only “current” data counts [NOTE: DENR keeps historic surface water ambient testing data to monitor change overtime, but apparently not interested in the fracking area.]  He was clearly incensed about the audacity of these grants; his presentation misrepresented several things detailed in the actual grant application [available online].  Reeder said that MEC and Div. of Energy, Mining & Land Resources were missing as named partners in the grant application [so was the Easter Bunny], and the grant did propose a coordinated study with EPA and USGS.  He said there is enough money and staff available in DENR to do a more targeted study [without EPA and USGS meddling?] closer to when drilling actually begins.  And, he said DENR Secretary John Skvarla wants to save taxpayer dollars and doesn’t want to fund worthless studies that hire temporary workers.  Vik Rao said the proposal was well-intentioned, but should have involved MEC.  Amy Pickle said there are only a few surface water ambient monitoring stations in the Deep River area, which was a concern raised in the 2012 DENR study report on fracking.  Ray Covington said he agrees with Reeder’s reasoning. 
From Public Comment:  George Matthis: River Guardian Foundation, EPA is flexible, as long as you meet goals.  Why turn down this grant?  Sends strong signal to public that Legislature is going after a job.  Citizens deserve better environmental protection, not going backwards.  Said MEC should request an independent commission to look into DENR.
Terese Vick:  Issue about Reeder, lots has happened that we will not know…probably political motive rather than budgetary.   Never heard a DENR Div. Director say have “plenty of money;” DENR constantly saying they can’t afford public meetings.  Perception and reality of environmental regulation are two separate things under this Administration.  If DENR said grant was in conflict with MEC, why was not MEC contacted before DENR refusal? Why wouldn’t this testing be beneficial to MEC?  Don’t think you know the whole story, trace the emails and breadcrumbs. 
Committee Reports:
1.  Water and Waste Management Committee; Chair, Dr. Vikram RaoMore thoughtful discussion on water and waste disposal rules, and further work on a white paper that considers the ability of industry to comply with wastewater disposal.  The disposal issue might keep industry away, per Rao.  New UIC Class II wells (injection deep underground) are currently prohibited in NC and Rao feels injection wells are inappropriate for this industry.  Reuse of fracking water will probably be required in the rules, but at the end of the process, how will remainder be handled.  Rao said at the end of fracking water reuse cycle, each operation would need to dispose of about a million gallons of concentrated solution, or about 24,000 barrels.  Rao has investigated commercial Reverse Osmosis facilities that could handle, but then still have a concentrate after this treatment.  If final concentration is not injected underground, and if ocean discharge is an option for North Carolina operators, treatment at a permitted Centralized Waste Treatment (CWT) would still be required by law as a precursor step.  His view, wastewater from oil and gas operations in the Triassic Basin can be treated at reasonable costs. Womack said NC could end up with an NPDES discharge permit that would allow them to dump into public waters [is he referring to ocean?].
2.  Oil and Gas Administration Committee; Chair, Charles Holbrook.   News from PA: A new way to collect rainwater from drilling pad to use in on-site fracturing by installing a subterranean liner system with manholes going down into compartments to collect lots of rainwater from pad and also capture diesel fuel and spills.  No data collection as yet, but this is promising idea for rain capture and reuse.  One-inch of rain on a drilling pad of 160,000 sq. ft. can generate 1.2 million gallons of water and could be reused for fracking.  
Holbrook made the case in a white paper that the regulation contained in SL 2012-143 requiring the establishment of efficient gas-oil ratios should be removed from relevant state statutes.  Holbrook said this is not practicable for NC [antiquated statutory language relating to conventional oil deposits, not unconventional gas extraction] and impossible to fix a standard ratio.  He said that operators will preferentially develop any oilier zones found to exist in a basin for obvious economic reasons, but they have no control over the hydrocarbon mix that comes out of any particular zone that has been hydraulically fractured. Therefore, attempting to regulate efficient gas-oil ratios is not an option for fracking. Committee voted to ask Legislature to remove that language from SL 2012:143. 
The Committee heard presentations on how other states are establishing “drilling blocks” so staff can begin drafting rules.  Holbrook cautioned that the State can’t dictate “specifics” of surface areas...the geology will determine the drill-out area.  Per Holbrook, the length of horizontal run will determine the acreage of a unit.  He noted that states have modified their drilling layout over time as new technology evolves.  Terminology: Drilling unit or drilling block?  Ken Taylor said “Drilling unit” means the area that can be efficiently and economically drained by one well. Also, drilling unit is usually defined as the area being regulated by the permit.  Note:  Plats showing drilling area are not filed with County Register of Deeds, but they will be submitted to the permit regulator (DENR).
The Wellhead Requirements rule set was sent to Rules Committee, approved, and was an agenda item for MEC.  Holbrook discussed the three-page rule that includes wellhead assemblies, well maintenance and site security, including placement of workzone and cautionary signage, fencing, equipment storage, gates, and permittee contact information. 
MEC voted Sept. 27 to approve the Wellhead Requirements rule set, as modified.
3.  Environmental Standards Committee; chair, George Howard.  Set-backs major concern for several meetings, and trying to find objective criteria, plus looking at other states.  Seems that 500-ft. is preferred, but struggling with set-backs from private water wells; 1,000-ft. may be too much because it could prohibit this industry. Rules will cover setbacks from dwelling units, property boundary, property boundary outside the “leased” block, public roads, surface waters, tank batteries and reuse water pits, Other states measure distance from wellhead, not edge of well-pad.  Colorado has 500-ft. standard, but also has 1,000-ft. from high-occupancy buildings...few of these in Lee County drilling area.  Staff should have a draft next meeting.  Womack mentioned waivers (by consent) from landowners to reduce setbacks to a minimum standard for “safety,” perhaps 150-ft.  Question of whether should also “prohibit” drilling in areas of concern.  Stakeholders suggested that a owner-granted “waiver” should be registered with Registrar of Deeds.  Holbrook suggested using Lee County GIS to visualize the various setbacks, and see what area is left.  Womack said setbacks are only for “health and safety,” there should be a rationale either thru science or economy.   Marva Price asked if MEC can apply to EPA for grant to find the science behind setbacks, since none seem to exist?  Womack said good idea [even though DENR just returned two grants?] 
Baseline and Subsequent Testing Requirements rule discussion, led by George Howard. The Rules Committee raised several issues for MEC discussion: 
(a) Can the rule allow one regulated permittee to use baseline water well data collected by an earlier permittee who took samples within the specified timeframe and within the intersecting radii of 5,000-ft.?  Jennie, from Attorney General’s (AG) office said there is concern about the statutory provision that all operators within 5,000-ft. radius must test wells, therefore can law “allow” data sharing between different operators.  AG research showed there is a separation between lease agreement and 5,000-ft. baseline testing vs. MEC’s purview and authority for “regulatory program” on granting a permit.  Womack: MEC’s regulatory authority could allow use of other data, but won’t know where contamination comes from, and who is accountable.  He referenced water hauling in PA when private wells were contaminated. Vik Rao: There was no baseline testing in PA, that was the problem.  Rao suggested allowing the second company to access well data from first company (if they agree); this rule is for baseline testing...access to data does not absolve presumptive liability.  Amy Pickle:  Establishment of presumptive liability will be decided in courts, not by MEC.  If well data collected by Co. A is then used by Co. B and that well shows degradation, the teasing out of which company is liable will go to court.  Operators will decide if they want to collect own data, or share.  Womack:  Maybe better to have ALL operators complete baseline testing to protect own interests.  Rao: Backed off his position on allowing sharing of data.  Consensus to forget data sharing, and require all operators to test all wells within their area of operation. 
(b) Reducing current Presumptive Liability of 5,000-ft. for water contamination. Charles Holbrook prepared a white paper on 5,000-ft. baseline testing, when most states use 1,500-ft.  Holbrook said the 5,000-ft. statutory rule [SL 2012:143] makes him “uncomfortable” since it is not based on an established practice, or standard.  After two decades of fracking there is not one documented case where fluid has migrated to shallow freshwater zones, he said.  The only leaking possible is through a ruptured casing; virtually impossible to move fluid to surface.  In Holbrook’s explanation, companies model the zones of fracture and gallons of fluid, sand, water to prop fractures open and treat the rock and water to optimize that fracture.  If runs amuck...if fracture expands beyond the model zone, that dramatically increases volume of water required and the pressure drops; therefore, operator knows immediately there is problem.  Technical aspect, even if could pump water, he says it won’t reach freshwater zone. When pumping into fracking zone, operator stops pumping when reaches “nirvana” so can get gas flow back. Holbrook’s bottom line: the larger you make this [presumptive liability] distance the more potential for legal problems.  Rao: Reason to believe 5,000-ft. requirement came about because of 5,000-ft. expected distance from lateral wells?  Holbrook responded that a “sound science” testing regime, would be 3x the width of drilling block, therefore 1,500-ft. to allow wide buffers.  PA got in trouble because of no baseline testing.  Rao disagreed saying studies suggest 2,000-ft. for baseline testing, and largest distance is 2,500-ft. in other states.  Holbrook would like MEC to petition the Legislature to reduce the presumptive liability (and therefore baseline well testing) from 5,000-ft. to 2,000-ft.  Womack suggested using Lee County GIS data to show wells within 5,000-ft. and wells within 2,000-ft. of a sample area; but continue with assumption of 5,000-ft. for rule-making.  
(c) Tracers and Environmental Defense Fund.  The current draft rule allows for use of tracer technology (if approved by DENR) mixed in the hydraulic fracturing fluid at an individual gas well, that would act as a substitute for subsequent testing using the full suite of chemicals; except even if this case the operator must test for dissolved methane, ethane and propane.  This proposal for using tracers as a surrogate for full secondary testing, has raised concern by Environmental Defense Fund, which works closely with the industry.  David Kelly, EDF, said tracers are more generally defined for oil and gas; this rule would limit testing via tracers to fracking fluid, instead of surface uses that could be larger players in contamination.  Further, Kelly said don’t replace the proposed “canary” list for subsequent water tests with these tracers, since it is not a surrogate.  Womack said he felt tracers are only necessary to point out the guilty party, and NOT a replacement for a testing using a subset chemicals.  Womack says wants to “incentivize” [actually not a word] tracers, but not mandate; therefore staff should rewrite this portion of rule...use of tracer is encouraged.  Rao to work on “canary” list to test chemicals, not just at wellbore but consider spills around well pad from storage and other sources of contamination.  Pickle: Concern about having a “thorough” canary list for surface spills as well.  Ken Taylor: Read original list for baseline and second test (if stuff travels to water well within 12 months, by the second test, it will show up), based on Rao’s work.  Rao: Will add additional aromatics to canary list and meet with tracer people.
Back to staff, more discussion at next Environmental Standards Committee meeting, October 24.
4.  Rules Committee; chair, Amy Pickle.  Wellhead requirements were discussed and approved (see #2).  All rules will reference “permittee” instead of “operator.”  She clarified the use of “shall” instead of “will” in rules.  “Shall” implies actors and actual action that will be judged vs. “will” when there is no action.  Rules Committee will provide more rule language guidance.  Womack asked who is keeping the list of what statutory changes are needed.  Pickle said that is tied to individual rules and DENR staff assigned to the Rules Committee should keep this summary list. 
5.  Study Group Reports
(a) Local Government Study Group, Womack reporting for Charles Taylor.  No further updates and remanded to staff for sending to Legislature. 
MEC voted unanimously to approve release of report [but not to “approve” the content of the report, so individual members could dissent.  Who?] 
(b) Compulsory Pooling Study Group, Ray Covington.   Said the report achieved a number of positive land-owner protections that Legislature should consider.  This report is routed through DENR to write a cover letter and send to Legislature. 
Note #1:  Covington did NOT say out loud that their recommendation would allow an operator to seek a pooling order when 90% of drilling acreage is under a lease...because it could actually force a majority of affected landowners (think residential subdivisions, lots of owners) into the pool.
Note #2:  DENR knows this is a hot potato...a potential “taking” of property for gas industry is sure to rile up VOTERS.  They say they are waiting to move this to Legislature until “drilling unit” rules are established...probably after the Nov. ELECTIONS.
(c) Funding Levels and Sources Study Group, Jane Lewis Raymond.  Recommended a two-part impact fee for local government:  first, a $2,000 flat fee; second, a fee ($1,800) based on the “stage” of fracture...up to 30 stages per well, which could result in $50,000/per well.  This would be placed in a state “trust fund” and each local government would have to apply for funds.  Since local government will feel impacts immediately, the report suggests they could:  (1)  apply for damages through state “trust fund"; (2) Municipalities can create Local Excess Agreements to have gas industry pay for road maintenance; (3) Charge property tax on wellhead equipment through ad valorum taxation.  
To recover the estimated $3 million annually in state costs to run this permitting program, suggest establishing a 1.5% severance tax, which is in addition to existing state severance tax of 5% on the value of produced natural gas liquids.  Since there is no data to estimate North Carolina gas reserves/potential, the group used Arkansas as an example, which applies a 1.5% severance tax to recover costs to the state...they are not looking to generate revenue.  Womack said this report is for cost-recovery only, not as a vehicle to generate revenue for North Carolina.  The final section of report reviewed a bond structure to recover costs for abandonment and reclamation. Those bonds would include a surface owner bond, geophysical exploration bond, well plugging and abandonment bond, and a site reclamation bond.
MEC voted unanimously to approve release of report to Legislature.
(d) Chemical Disclosure and Trade Secrets, Jim Womack.  Says he will bring his “revised” rule and recommendations back to MEC for comment October 25.  
Diana Hales, retired

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