State Says St. Tammany is "Out of Line" with Fracking Lawsuit

With anti-fracking citizens and activists loudly protesting plans by Helis Oil & Gas Co. to drill a well in St. Tammany Parish (northeast of Mandeville) that anticipates the use of "hydraulic fracturing" to extract hydrocarbons, the parish decided to sue the Commissioner of Conservation, who heads the Office of Conservation within the Louisiana Department of Natural Resources.

The lawsuit, which was filed in East Baton Rouge Parish state court in June 2014, seeks:

(1) a declaration that the zoning ordinances of St. Tammany Parish be given "primary consideration" by the Office of Conservation in its handling of permit applications that pertain to the parish;

(2) an injunction halting the Office of Conservation's issuance of orders establishing drilling units in the parish "until such time as [the Commissioner] can prove compliance with all laws not currently being complied with, as well as regulations that are admitted should be in place, but are not"; and

(3) a declaration that "St. Tammany Parish has the authority to ban the practice of hydraulic fracturing, or fracking, during oil and gas well drilling operations".

A September 2014 amendment to the lawsuit adds a fourth request, that the Court declare the drilling unit for the proposed well "invalid, null, void, and of no effect."

Can St. Tammany Use Zoning to Deny Drilling Permits?

What does St. Tammany's request that the Commissioner be required to give parish zoning ordinances "primary consideration" really mean?  Is St. Tammany arguing that if its zoning ordinances prohibit drilling wells on certain property, that the Commissioner of Conservation is legally barred from issuing a drilling permit?  As the State of Louisiana (through the Commissioner) noted in its legal memorandum in support of "exceptions" that seek to have the lawsuit thrown out of court, Louisiana law clearly provides that the Commissioner, not parish governments or any other agencies or political subdivisions, has exclusive authority to issue drilling permits.

The issuance of a permit by the commissioner of conservation shall be sufficient authorization to the holder of the permit to enter upon the property covered by the permit and to drill in search of minerals thereon.  No other agency or political subdivision of the state shall have the authority and they are hereby expressly forbidden to prohibit or in any way interfere with the drilling of a well or test well in search of minerals by the holder of such permit.  La. R.S. 30:28(F).

The State argues that local ordinances purporting to regulate drilling or govern the consideration of permit applications are preempted by the pervasive state regulatory scheme, citing Energy Management Corp. v. City of Shreveport, 397 F.3d 297 (5th Cir. 2005) and 467 F.3d 471 (5th Cir. 2006).  St. Tammany argues that the legislature granted it express authority to regulate land use through zoning ordinances, citing La. R.S. 33:4776.  However, a longstanding general rule of statutory interpretation is that "the specific controls the general."  State in Interest of A.C., 643 So. 2d 719, 730 (La. 1994).  While St. Tammany has been granted general authority to enact zoning ordinances, the Office of Conservation has been granted specific and exclusive authority to grant drilling permits.  Does the statute that expressly forbids St. Tammany from prohibiting or interfering with the drilling of a well trump the statute that grants St. Tammany general authority over zoning in the parish? 

Can St. Tammany Secure a Parish-Wide Unitization Moratorium?

Relying heavily on the findings of a legislative audit of the Office of Conservation, St. Tammany argues that "it would be ill-advised and potentially catastrophic to allow another unit to be constructed when the Office of Conservation is incapable of regulating and maintaining current wells."  Pet. at ¶ 35.  That certainly reads like a public policy argument and not a grounds for what would effectively be a sweeping, open-ended moratorium on the issuance of drilling units in St. Tammany Parish until such time as a state court judge determined that the Office was in compliance with "all laws" and future regulations (extremely broad language that seems problematically vague).  Notably, St. Tammany did not cite any legal authority for the requested moratorium in its petition.  It remains to be seen whether the parish will offer persuasive authority in opposition to the State's effort to dismiss the requested injunction.

As part of its argument seeking to dismiss the parish's request for a moratorium on unit orders, the State points out that such orders are not drilling permits.  Department of Natural Resources communications director Patrick Courreges said that a drilling and production unit means that "if the well is drilled and is successful, this is who gets a piece of it."  "Getting a piece of it" means sharing in royalties from production.  The State has argued that "divvying up mineral rights via compulsory unitization has no relation whatsoever to the irrelevant and/or spurious factual allegations of the Plaintiff."  State's Memorandum in Support of Exceptions at p. 11.

After the filing of St. Tammany's lawsuit and the State's exceptions, the Commissioner of Conservation issued a drilling and production unit order governing the property where Helis has proposed to drill its well.  Thus, the request for a moratorium on such orders would have no bearing on the proposed well that prompted the parish's lawsuit.  With the order already issued, St. Tammany has added a new request for the unit order to be declared invalid (which is discussed below). 

A Challenge to the Prohibition of Advisory Opinions?

St. Tammany wants a declaration from the Court that "St. Tammany Parish has the authority to ban the practice of hydraulic fracturing, or fracking, during oil and gas well drilling operations".  According to the Louisiana Supreme Court, "Cases submitted for adjudication must be justiciable, ripe for decision, and not brought prematurely."  Louisiana Federation of Teachers v. State, 94 So. 3d 760, 763 (La. 2012).  To be a justiciable controversy, there needs to be "an existing actual and substantial dispute, as distinguished from one that is merely hypothetical or abstract".  Id.  "[T]he dispute presented should be of sufficient immediacy and reality to warrant the issuance of a declaratory judgment."  Id.  In a nutshell, "The jurisprudence of this court is well settled that courts will not render advisory opinions."  Id.

The State indicated that it was unaware of any St. Tammany ordinance that bans fracking, and the parish's lawsuit does not identify any such ordinance.  Asking the Court to declare that "St. Tammany Parish has the authority to ban the practice of hydraulic fracturing, or fracking, during oil and gas well drilling operations" when the parish has not passed such an ordinance appears to be a textbook example of seeking a prohibited advisory opinion.  We will have to wait for St. Tammany's memorandum in opposition to the State's exceptions to see what the parish's response is to this legal argument.

Seeking to Invalidate the Unit Order

St. Tammany's Amended Petition adds a request that the August 29, 2014 unit order issued by the Commissioner of Conservation be declared invalid because the establishment of the drilling unit violated the St. Tammany Parish Unified Development Code.  The parish appears to argue that because the drilling unit encompasses land that is not zoned for drilling, it must be invalid.  In addition to being subject to the State's legal arguments discussed above, the State might argue that another shortcoming in this request for relief is the fact that a unit order is not a drilling permit.  Since the unit order does not authorize drilling, it is unclear how, even if parish zoning ordinances were applicable, it violates such ordinances.  As discussed above, a unit order is not a permit to drill.

Where Things Go From Here

The State argues that "[t]he Parish is simply out of line in its effort to use unorthodox and premature litigation to infringe on the deliberative process of an independent state agency" and has asked the Court to grant its exceptions and dismiss all of the parish's claims.  As of the date this blog is being posted, a hearing on the State's exceptions is set for October 27, 2014.  However, on September 10, 2014 Helis applied for a drilling permit, and on September 12, 2014, St. Tammany filed a motion seeking to get before the Court for a hearing as soon as possible.  It remains to be seen whether St. Tammany can offer any winning responses to the well-supported exceptions seeking to dismiss the lawsuit.

Several news articles addressing this litigation can be found at:

http://www.theneworleansadvocate.com/community/crescentcity/10255944-171/st-tammany-seeks-to-block

http://www.nola.com/politics/index.ssf/2014/09/st_tammany_parish_seeks_quicke.html

http://louisianarecord.com/news/262864-st-tammany-parish-sues-to-prevent-fracking-cites-concerns-over-aquifer

Environmental Groups Challenge Fracking Permits

A lawsuit filed October 16, 2012, in Alameda County Superior Court on behalf of the Center for Biological Diversity, Earthworks, Environmental Working Group, and Sierra Club, alleges that the California Department of Conservation, Division of Oil, Gas, and Geothermal Resources (“DOGGR”) has failed to consider or evaluate the risks of fracking as required by the California Environmental Quality Act (“CEQA”). Specifically, the suit alleges that the DOGGR violated CEQA “by issuing permits for oil and gas wells based on boilerplate negative declarations that do not provide the required environmental review, or let alone even mention, the impacts of hydraulic fracturing.”

According to a Sierra Club press release, the DOGGR—the state agency charged with regulating all oil and gas well activity in California—acknowledges “it has not permitted or monitored the impacts of fracking and has never formally calculated the potential environmental and health effects of the practice, even as it continues to approve new permits for oil and gas wells.” The lawsuit asks the court to issue “[a]n injunction enjoining the DOGGR from the approval of any further permits for oil and gas wells where hydraulic fracturing may occur within the state of California unless and until it complies with the requirements of CEQA by considering, evaluating, and mitigating the environmental and public health impacts associated with hydraulic fracturing.”

Earthjustice attorney, George Torgun, who represents the environmental groups, stated

“Right now, the people of California don’t know where or when the drillers are fracking, what chemicals they are using, what pollutants they are releasing into the air and water, and what other risks they’re taking. That’s because the state hasn’t required them to disclose any information on fracking activities.”

Some other states, including Louisiana, have adopted regulations requiring companies engaged in fracking to report the chemicals used in their fracking fluids.

 

National Research Council Concludes that Hydraulic Fracturing Does Not Pose a High Risk for Causing Earthquakes

The National Research Council has issued a report which concludes that hydraulic fracturing of wells for natural gas production "does not pose a high risk" for causing earthquakes.

The study examined the potential for a variety of types of energy development projects to cause earthquakes.  The study began after the U.S. Congress directed the Department of Energy to request that the National Research Council "examine the scale, scope, and consequences of seismicity induced during fluid injection and withdrawal activities related to geothermal energy development, oil and gas development including shale gas recovery, and carbon capture and sequestration (CCS)."  The National Research Council stated:

Three major findings emerged from the study:

(1) the process of hydraulic fracturing a well as presently implemented for shale gas recovery does not pose a high risk for inducing felt seismic events;

(2) injection for disposal of waste water derived from energy technologies into the  subsurface does pose some risk for induced seismic activity, but very few events have been documented over the past several decades relative to the large number of disposal wells in operation; and

(3) CCS, due to the large net volumes of injected fluids, may have potential for inducing larger seismic events."

The report noted that, "[a]lthough induced seismic events have not resulted in a loss of life or major damage in the United States, their effects have been felt locally, and they raise some concern."  The report suggested that the largest number of induced seismic events related to the energy industry arise from geothermal operations.  According to the report, 300 to 400 seismic events large enough to be felt are likely caused each year in the U.S. by so-called "vapor-dominated" geothermal operations, which seek to recover geothermal energy that is contained primarily in steam found in underground rock formations.  Another 10 to 40 seismic events large enough to be felt are caused each year in the U.S. by "liquid-dominated" geothermal operations, which seek to recover  geothermal energy found in hot water located in underground formations, and 2 to 10 seismic events large enough to be felt likely are caused by geothermal operations that seek to recover geothermal energy found in hot dry rocks underground.

In contrast, hydraulic fracturing is "suspected, but not confirmed" as the cause of one seismic event large enough to be felt in the U.S. (in Oklahoma) during the more than 60 years that hydraulic fracturing has been used.  And "only one case of felt seismicity" caused by hydraulic fracturing has been "confirmed" anywhere in the world (in Great Britain).  The report concluded that "[t]he very low number of felt [seismic] events relative to the large number of hydraulically fractured wells for shale gas is likely due to the short duration of injection of fluids and the limited fluid volumes used in a small spatial area."

Some mainstream media reports have attempted to link additional seismic events to fracturing, but government authorities and scientists have concluded that those events were either natural or induced by underground waste disposal activities, rather than hydraulic fracturing.  The report stated that "[r]educing injection volumes, rates, and pressures have been successful in decreasing rates of seismicity associated with waste water injection."

Other oil and gas practices are suspected of causing a handful of induced seismic events according to the report.  For example, the report stated that secondary recovery operations, which the oil and gas industry has been performed at approximately 108,000  wells, is suspected of having induced seismic activity at 18 locations, and hydrocarbon withdrawals or suspected of having induced seismic activity at 20 locations. 

The report also noted that various human activities other than those associated with fluid injections and withdrawals also are suspected of having induced seismic events.  These activities include impounding large reservoirs behind dams, using controlled explosions related to mining, and conducting underground nuclear testing.

The report recommended that "best practices" be developed to minimize the chance of induced seismic activity from each type of energy activity that involves fluid injection or withdrawal.  The report stated that the basic mechanism by which human activity can caused induced seismic activity is well understood, and is caused either by changes in the pressure of fluids found in the pore spaces of underground formations, or changes in subsurface stresses.  But there are some gaps in knowledge, and modeling and predicting induced seismic activity is difficult because of the complexity of underground rock formations and the lack of knowledge about local subterranean stresses.  The report recommed that additional research be done. 

Although the report stated that carbon sequestration and capture has the potential for inducing larger seismic events than those typically caused by other human activities, the report also noted that definitive conclusions regarding the likelihood for CCS activities to induce seismic activity are difficult to make because of the lack of experience with large scale CCS projects.  

A copy of the report is available from National Academies Press.

New Study Concludes Natural Gas Emissions are Lower than EPA Estimates

Earlier this month the American Petroleum Institute ("API") and America's Natural Gas Alliance ("ANGA") released a study regarding the amount of natural gas emitted from various sources during unconventional natural gas production.  The study concludes overall emissions are about half what the EPA estimates.  API and ANGA state that the estimates made in their study are more reliable than the estimates made by the EPA because the API/ANGA study is based on data from approximately "91,000 wells distributed over a broad geographic area and operated by over 20 companies," while "EPA's estimates were based on a small set of data submitted by a limited number of companies."  The new study is entitled "Characterizing Pivotal Sources of Methane Emissions from Unconventional Natural Gas Production."

What Accounts for the Large Difference Between the Estimates? 

The most dramatic difference between the API/ANGA estimates and EPA estimates relate to emissions during liquids unloading (a process in which liquid is removed from a natural gas wellbore so that the liquid does not obstruct the flow of gas).  API/ANGA's survey showed that a lower percentage of wells vent to the atmosphere than the EPA assumed and that the wells that vent do so for a shorter time than the EPA assumed.  The API/ANGA study estimates that emissions during liquids unloading are 86% lower than the EPA estimates.  API/ANGA's study also found that the total emissions during the re-fracturing of wells is much lower than the EPA estimated ─ 72% lower.  The main explanation for the difference in estimates is that API/ANGA found that the number of wells that are re-fractured is much lower than the EPA estimated. 

Why Do the Rates of Emission of Natural Gas Matter? 

Emissions of natural gas are undesirable because volatile organic compounds ("VOCs") can contribute to ground level ozone formation and because methane (the principal component of natural gas) is a greenhouse gas.  The EPA has devoted increased attention to emissions from the oil and gas industry.  For example, the EPA recently published new regulations that aim to decrease emissions of natural gas and VOCs during the production, storage, and transport of oil and gas.  Opponents of the oil and gas industry, and opponents of hydraulic fracturing, also have devoted increased attention to such emissions.

Links 

Golden Rules for a Golden Age of Gas

Last week the International Energy Agency released an interesting report entitled "Golden Rules for a Golden Age of Gas."  The gist of the report is that unconventional natural gas ─ shale gas, coalbed methane, and tight gas ─ is a vast energy source that can be safely and economically produced, but legitimate environmental concerns exist, and those concerns must be better addressed by industry and government, or political opposition will hamper the development of unconventional gas.

Natural gas is poised to enter a golden age, but will do so only if a significant proportion of the world's vast resources of unconventional gas ─ shale gas, tight gas and coalbed methane ─ can be developed profitably and in an environmentally acceptable manner."

The report states that a "bright future for unconventional gas is far from assured" because there are concerns about the footprint of drilling activity, water usage, air emissions, and the potential for groundwater contamination.  The report concludes:

The technologies and know-how exist for unconventional gas to be produced in a way that satisfactorily meets [the environmental] challenges, but a continuous drive from governments and industry to improve performance is required if public confidence is to be maintained or earned."

The report states that industry must commit to the highest practicable standards and government must devise science-based regulatory regimes in order to generate the public confidence necessary to overcome political opposition to the growth of unconventional gas.  The IEA's report outlines a series of "Golden Rules" for appropriate environmental and social practices that the IEA believes will generate sufficient public trust so that unconventional gas can meet its enormous potential.

The report is long (over 130 pages), but is interesting and thought-provoking.  You can get the high points from the Executive Summary, which is just over three pages long.  It is well worth reading if you are interesting in the development of unconventional gas, the opposition to that development, and the appropriate ways to address concerns regarding development of unconventional gas.

Oklahoma Adopts Regulations for Mandatory Disclosure of Hydraulic Fracturing Fluid Composition

Oklahoma has given final approval to regulations that will require oil and gas producers to disclose the composition of fluids used to hydraulically fracture wells in the state, reports Jay F. Marks of the news outlet NewsOK. The new regulations will go into effect July 1, 2012.

The regulations require operators to disclose on a well-by-well basis

  • the name of the operator
  • the type of base fluid used (this is typically water, but can be some other substance)
  • the trade name, supplier, and general purpose of each substance intentionally added to the base fluid
  • the identity, Chemical Abstracts Service (CAS) number, and maximum concentration for each ingredient in each substance intentionally added to the fracturing fluid
  • the API number of the well (an identification number unique to each well)
  • the longitude and latitude of the surface location of the well, and
  • the dates on which hydraulic fracturing operations began and ended.

The information must be disclosed within 60 days of the operator completing hydraulic fracturing operations. The operator must either post the information on the FracFocus website or send the information directly to the Oklahoma Corporation Commission, the agency that regulates the oil and gas industry in Oklahoma. If the operator submits the information to the Corporation Commission, the Commission will post the information on FracFocus. 

FracFocus is a website that has become a central place for posting the composition of hydraulic fracturing fluids.  Some companies voluntarily post information there.  In addition, several of the states that have enacted mandatory disclosure requirements direct companies to make their required disclosures by posting information on FracFcous, where it is readily accessible to the public.

Under Oklahoma's new regulations, a producer need not disclose information that the producer contends meets the standards to constitute a "trade secret" under the Uniform Trade Secrets Act, 78 Okla. St. Ann. §§ 85-94. In such circumstances, the operator must still disclose the chemical family to which a compound belongs. Also, the Corporation Commission can require a written explanation of the trade secret claim.

The Corporation Commission also has made available a document that includes copies of public comments regarding the proposed drafts of the regulations, the Commission's responses to the comments, and the changes made to the drafts of the regulations.

Dominion and Sierra Club Battle Over Proposed LNG Export Facility

On Friday, Dominion filed suit, asking a state court in Calvert County, Maryland to confirm the company's right to construct and operate a liquefied natural gas ("LNG") export facility at the company's existing LNG terminal at Cove Point in Lusby, Maryland.  Dominion obtained preliminary authorization from the Department of Energy last year to export LNG, which Dominion plans to do from its terminal at Cove Point.  But the Maryland Chapter of the Sierra Club issued a statement in April claiming that it has the right to veto the proposed export facility under a 2005 agreement with Dominion.

Background of the Cove Point Terminal

Dominion's Cove Point LNG terminal was originally owned by Columbia Gas, which constructed the terminal as an LNG import terminal in the 1970s.  Columbia only operated the facility as an import terminal for a couple of years, but in the 1990s it added liquefaction capability at the facility for use in providing "peaking service."  This involves liquefying natural gas and storing it during periods of low demand, then regasifying and selling it during periods of peak use. 

Dominion acquired the facility in 2002 and applied to the Federal Energy Regulatory Commission for authority to expand the facility and use it again for LNG imports.  In 2005, Dominion entered an agreement with the Sierra Club and Maryland Conservation Council, in which those environmental organizations agreed not to oppose Dominion's expansion of the terminal in return for Dominion's agreement regarding the protection of certain other nearby areas.  Since then, Dominion has used the facility for LNG imports.

What led to the current dispute?

Up until the last few years, there were projections that the United States would remain dependent on natural gas imports, including LNG imports, into the foreseeable future.  But domestic production of natural has increased dramatically in the last few years, in large part because of the use of horizontal drilling and hydraulic fracturing to produce natural gas from shale formations.  That has led to decreased imports, and to such a plentiful domestic supply of natural gas that companies are planning to export natural gas.  Dominion applied to the Department of Energy for permission to export natural gas and received preliminary approval to do so last October.

But on April 26, 2012, the Sierra Club sent a letter to Dominion, demanding that it cease plans to export natural gas from Cove Point.  The same day, the Sierra Club issued a press release declaring its opposition to Dominion's export plans.  The Sierra Club contends that the 2005 agreement prevents Dominion from expanding the terminal or from using it as an export facility.  Thus, contends the Sierra Club, Dominion cannot export LNG from Cove Point without the Sierra Club's consent.  Further, the Sierra Club states that it will not give that consent.  In part, the Sierra Club says it objects to expanding the footprint of the terminal, which Dominion plans to do by building additional liquefaction capacity, which would be needed in order to operate the terminal as an export facility.  But the Sierra Club stated that Dominion's operation of the terminal as an export facility would be "unacceptable ... even if Dominion confined its new construction to the existing plant site."  Why?  Because the export of natural gas would encourage more natural gas drilling and the use of hydraulic fracturing, which the Sierra Club opposes.

Dominion's Contentions and its Lawsuit

Dominion Cove Point LNG, L.P. filed suit in the Circuit Court for Calvert County against the Sierra Club, the Maryland Chapter of the Sierra Club, and the Maryland Conservation Council.  Dominion disputes the Sierra Club's contention that the 2005 agreement limits Dominion to using the Cove Point terminal for LNG imports.  Further, contends Dominion, the Sierra Club's opposition to Dominion's export of LNG from Cove Point has very little to do with concern about LNG exports, construction activity at Cove Point, or an enlarged footprint for the terminal.  Instead, the Sierra Club's primary reason for opposing the export of LNG is that the Sierra Club opposes drilling for natural gas and the use of hydraulic fracturing, and the increased availability of LNG export facilities will encourage natural gas drilling.  To support its point, Dominion points to the Sierra Club's "Beyond Natural Gas Initiative."  Further, both the Sierra Club's April 26 press release and its April 26 letter to Dominion give prominent attention to the Sierra Club's opposition to hydraulic fracturing and natural gas drilling, even though neither of those are directly at issue in Dominion's proposal.  Dominion's lawsuit seeks a declaratory judgment that the 2005 agreement does not prevent it from building and operating LNG export facilities at its Cove Point terminal. 

In addition to arguing that the 2005 agreement does not prevent such use, Dominion points out that the proposed project would result in an additional $40 million per year in property tax revenue for Calvert County, 70 to 100 permanent jobs in Calvert County, and 2500 to 3100 construction jobs.

Dominion would like to begin construction in 2014, with a schedule that would call for putting the proposed export facility into service in 2017, pending necessary regulatory approvals and the negotiation of terminal service agreements.

Why is this Important Beyond Calvert County, Maryland?

The resolution of Dominion's lawsuit will turn on the court's interpretation of the language in the 2005 agreement, and the court's interpretation of that language is not likely to have a direct effect on any other disputes.  The importance of this dispute is that it shows the Sierra Club's determination to oppose projects that will encourage ─ even indirectly ─ greater drilling for natural gas and use of hydraulic fracturing.  Natural gas is the cleanest burning of all fossil fuels, and there have been projections that the plentiful supply of natural gas will contribute to an increased use of gas and a decreased use of coal for generating electricity.  Will the Sierra Club oppose increased drilling for natural gas even if less drilling mean more coal use in the U.S.?  Will the Sierra Club continue to oppose natural gas exports if less exports would mean more coal use abroad?

Resources

City of Loveland Imposes Moratorium on Oil and Gas Activity

Last Tuesday night, the Loveland City Council enacted an "emergency ordinance" that imposes a nine month moratorium on its issuance of any land use permits relating to oil and gas activity. 

Under Loveland's current zoning, oil and gas operations are prohibited in all of the City's zoning districts except "Industrial" and "Developing Resource."  Further, even in those areas, oil and gas activity is not allowed unless the City approves the proposed activity after the proposal undergoes a special review.   The Centerra area of Loveland is not governed by one of the City's normal zoning districts, and instead certain "Millennium Planned Unit Development" restrictions apply.  Although those restrictions do not expressly prohibit oil and gas activity, such activities are not currently allowed in the area.  The City Manager stated that the moratorium will give the City time to consider whether it wishes to enact zoning ordinances that place even greater restrictions on oil and gas activity than those that exist now.

The moratorium was enacted as an "emergency ordinance" because the Council wanted to enact it Tuesday night, which also was the night that the ordinance was first proposed.  Under the Council's normal rules of procedure, a proposed ordinance generally must be introduced at one meeting and enacted at a subsequent meeting.  But an "emergency ordinance" can be passed at the same meeting at which it is proposed.

The materials for last week's meeting included a memorandum from Loveland's City Manager, who stated that a number of citizens requested during the May 1, 2012 Council meeting that the Council implement a moratorium.

A number of other Colorado communities, including Longmont, Colorado Springs, El Paso County, Erie, and Boulder County.  In addition, Fort Collins is considering a moratorium.

The ordinance does not revoke any existing land use permits.  Thus, if someone already has an approved land use permit for oil and gas activity, that activity apparently will be allowed to proceed.

Video Interview Regarding Hydraulic Fracturing: Discussing the Vermont Fracking Ban with LXBN TV

Just earlier today, after writing a post on the subject yesterday, I had a chance to discuss the Vermont hydraulic fracturing ban with Colin O'Keefe of LXBN TV. In the short interview, I explain just how extensive this new law is, why it happened in Vermont first and whether or not we're going to see more legislation like this in the future.

Vermont Becomes First State to Ban Hydraulic Fracturing

Yesterday, Governor Peter Shumlin signed legislation making Vermont the first state to outlaw hydraulic fracturing.  The legislation also prohibits anyone from storing or treating hydraulic fracturing wastewater anywhere in the State.

The legislation also directs Vermont's Secretary of Natural Resources to submit a report by January 15, 2015 recommending how hydraulic fracturing should be regulated in the event the ban is rescinded.  The report is to include discussion relating to how hydraulic fracturing wastewater should be treated, how water withdrawals for hydraulic fracturing can be managed, and how traffic issues should be addressed.  The legislation requires the Secretary of Natural Resources to provide a second report by January 15, 2016.  The second report is supposed to discuss the environmental impact of hydraulic fracturing and its potential effects on human health, summarize relevant peer‑reviewed studies, and make a recommendation regarding whether hydraulic fracturing should be prohibited.

The website for the Vermont State Legislature can be used to view the original and interim drafts of the legislation as it made its way through the legislature.  Governor Shumlin's official website has a video of a statement the Governor made regarding the legislation.

To date, there has not been any shale play activity in Vermont, though some experts state that a shale formation may extend beneath one corner of the state.  Indeed, Vermont has never had much oil and gas activity of any kind, whether conventional or unconventional.  Baker‑Hughes rig counts show that there are no oil or gas drilling rigs currently operating anywhere in the state, and that it has been years since any rotary rig drilled for oil or gas in Vermont.  The Vermont Geological Survey states that there never has been a productive oil or gas well in Vermont and that it has been about 28 years since the last dry hole was drilled. 

Court Dismisses Hydraulic Fracturing Lawsuit for Lack of Evidence

In what may be the first hydraulic fracturing case to reach final judgment, a court in Denver, Colorado has dismissed the plaintiffs' claims on summary judgment, citing a lack of evidence.  The case, Strudley v. Antero Resources Corporation, was filed in state court on behalf of a family of four.  The Strudleys alleged that they had suffered various health problems before moving out of their home in Silt, Colorado.  The Strudleys asserted that their alleged health problems were caused by exposure to contaminated air and water, and that the alleged contamination was caused by the defendants' oil and gas activities, including hydraulic fracturing.

In its judgment, the court noted that the Colorado Oil and Gas Conservation Commission had conducted an investigation and concluded that the Strudleys' water supply had not been affected by oil and gas operations.  Further, the plaintiffs' own environmental expert could go no further than to state that the results of his analyses of the plaintiffs' water supply "could be consistent with contamination from gas well chemicals or production waters."  He could not state an opinion that the defendants' activities had actually caused any contamination.

The court also noted that the Strudleys' medical expert reached "no opinion as to whether exposure was a contributing factor to Plaintiffs' alleged injury or illness."  The medical expert could only state that the plaintiffs' symptoms coincided in time with the defendants' wells being brought into production. 

The court's judgment dismissing the case was signed last week, on May 9, 2012.

Hydraulic Fracturing: EPA Says Water in Dimock is Safe

On Friday, the U.S. Environmental Protection Agency released additional test results from water samples collected in Dimock, Pennsylvania and again declared that none showed unsafe levels of contaminants.  The recently-released test results are consistent with previous test results in which EPA found no unsafe levels of contamination.

An EPA spokesman confirmed that the test results "did not show levels of contaminants that would give EPA reason to take further action."

The EPA's testing program was initiated in response to complaints from residents of Dimock about their water quality, which some of the residents blamed on local oil and gas activity, including hydraulic fracturing.  The EPA has now completed four rounds of water sampling and testing, with samples being collected from approximately 61 homes in the small northeastern Pennsylvania town.  The EPA has not found any results that fall outside federal drinking water standards.

A spokesman for Cabot Oil & Gas Corporation, which operates in the area, said: "Cabot is pleased that EPA has now reached the same conclusion of Cabot and state and local authorities resulting from the collection of more than 10,000 pages of hard data — that the water in Dimock meets all regulatory standards."

The test results (a large file) can be found here.

Hydraulic Fracturing: EPA Releases Guidance for Safe Drinking Water Act Permitting for Use of Diesel in Fracturing Fluid

Last week, the EPA announced the release of guidance for its personnel to utilize in evaluating applications for Safe Drinking Water Act ("SDWA") permits for the use of diesel fuel in fracturing fluid.  The guidance includes guidance regarding what constitutes "diesel" for purposes of the SDWA, as well as factors to consider in evaluating permit applications.

Why does the guidance focus on the use of "diesel" in fracturing?  The SDWA generally prohibits any underground injection that is not authorized by permit or some other rule.  But under the SDWA, hydraulic fracturing is not classified as an "underground injection," unless diesel fuel is included in the fracturing fluid.  That is why the guidance specifically relates to hydraulic fracturing operations in which diesel is used in the fracturing fluid.

Why was a guidance document needed in the first place?  In the past, the EPA has not required SDWA permits for fracturing, even when diesel is included in the fracturing fluid, but the EPA announced in 2010 that companies would have to obtain SDWA permits before using fracturing fluid containing diesel.  Because the EPA has not previously required permits, both companies and regulators were uncertain what standards would be used in evaluating permits.  Also, because the SDWA does not define "diesel," there was uncertainty regarding what substances would be considered "diesel" for purposes of SDWA permitting requirements.  The guidance document is the EPA's attempt to provide clarification.

Where does the guidance apply?  The guidance will apply only in states where EPA administers the SDWA program.  Many states have "primacy," meaning that those states have their own SDWA regulatory programs that meet certain federal standards, and those states have been delegated the responsibility to administer SDWA enforcement within the state.  The guidance document will not apply in the states that have primacy, but those states may adopt the  new guidance standards if they choose.

Hydraulic Fracturing: BLM Issues Proposed Regulations for Fracturing on Federal and Indian Lands

On Friday, the Department of Interior's Bureau of Land Management released its draft of proposed new regulations for hydraulic fracturing operations performed on federal lands and Indian lands.  The draft rules would require companies to disclose on a well-by-well basis a variety of information, including the identity of all chemicals used in hydraulic fracturing operations.  That information generally will then be publicly disclosed. 

The draft regulations also include provisions that BLM says will improve assurances of well-bore integrity, in order to prevent fluids from escaping the well, and confirm that operators have a plan in place to properly handle and fracturing flowback water.  Once in place, the regulations will apply to a large number of wells.  BLM estimates that about 3400 wells are hydraulically fractured on federal lands or Indian lands each year, about 90% of the total number of wells drilled on those lands. 

The regulations will require companies to obtain BLM's approval of any hydraulic fracturing operation prior to conducting the operation.  The well operator can seek approval for fracturing at the same time that the operator submits an application for a permit to drill, or the operator can seek approval later.  So that BLM will have sufficient information to evaluate  requests for authority to conduct hydraulic fracturing, the draft rules would require the operator to give BLM a report that includes:

  • a geological description of the formation that would be hydraulically fractured, as well as the depths of the top and bottom of the formation   
  • the source location for the water that would be used in fracturing 
  • the type of proppants to be used in the fracturing   
  • the anticipated pressures to be used in the fracturing operation     
  • an estimate of the total volume of fracturing fluid to be used    
  • an estimate or calculation of the anticipated fracture length           
  •  the estimated volume and composition of flowback water that would be recovered after fracturing    
  • the methods the operator intends to use to manage flowback (including information regarding any pits or ponds to be used), and
  • the operator's plans for eventual disposal or reuse of the flowback.   

The operator also will be required to submit a cement bond log to the BLM prior to fracturing in order to ensure mechanical integrity of the wellbore.  The purpose of this log is to verify that there are no voids in the cement that is supposed to fill the annulus between the well's casing and the well's outer wall, thereby providing a seal to prevent vertical migration of fluids through the annulus.  In addition, the operator will be required to perform a pressure test of the wellbore prior to fracturing, to ensure that it can withstand the maximum pressures expected during fracturing.

During fracturing, the operator would be required to continuously monitor the annulus pressure (an unexpected change in the pressure could be an early indicator of a problem with well integrity).  The draft regulations would require operators to store the flowback water recovered from the fracturing operation in tanks or lined pits to minimize the chance for an unintentional release.  After the fracturing operation is complete, the operator must provide BLM with a report that includes such information as the actual amount of water used and recovered, and a discussion of any ways in which the fracturing operation deviated from what was expected.  

The post-fracturing report also must identify each additive used in the fracturing fluid by trade name, additive purpose (such as biocide, corrosion inhibitor, etc.), and the Chemical Abstracts Service Registry Number (which provides a unique identification for each known chemical compound).  The information provided to BLM will be made public unless the operator submits with the report a claim that a particular additive constitutes a trade secret that is protected against disclosure by some existing federal law. 

An operator that makes a trade secret claim must identify the federal law that the operator claims provides the protection against disclosure.  If a operator makes such a claim, the BLM will not publicly disclose the identity of the additive unless the BLM determines that federal law does not provide the protection the operator claims.  If the BLM makes such a determination, it will give the operator at least ten days notice before publicly disclosing the identity of the additive for which the BLM determined the trade secret claim was invalid. 

BLM states that it plans to make the publicly-disclosed information available on the internet.  It is evaluating the possibility of making FracFocus the platform for such disclosures.  FracFocus began as a website for well-by-well disclosures of fracturing water composition by operators who were willing to make voluntary disclosures.  But several states that have adopted requirements that operators disclose the composition of fracturing fluid have directed operators to post the information on FracFocus, which has now become a central source for such disclosures.

The draft regulations will soon be published in the Federal Register, after which there will be a 60-day public comment period on the draft. 

In addition to the draft regulations, the Department of Interior issued a press release regarding the draft and BLM's analysis of the likely economic impact of the proposed regulations.

Nova Scotia Extends its Review of Hydraulic Fracturing to 2014

Nova Scotia issued a statement earlier this week announcing that it will extend its review of hydraulic fracturing to mid-2014 in order to give the province more time to study the process.  Environment Minister Sterling Belliveau stated, "It is important we have the appropriate rules in place around this activity to protect the environment."  Energy Minister Charlie Parker stated that the province "will take time to learn from jurisdictions with significantly more experience in this area than Nova Scotia."  The province's statement indicates that no hydraulic fracturing operations will be approved during the review process, but that traditional oil and gas operations will continue.

The province also has an information page on its website regarding hydraulic fracturing.

EPA Announces Delay in Effective Date of New Air Rule for Hydraulic Fracturing

Yesterday, the EPA announced finalization of new rules designed to reduce emissions of volatile organic compounds ("VOCs") in oil and gas operations, but the effective date of a much-watched part of the new rules is being delayed until January 1, 2015.  That is the portion of the new rules that will require so-called "reduced emissions completions" or "green completions" in hydraulic fracturing of natural gas wells.

The requirement for "reduced emissions completions" relates to the flowback portion of hydraulic fracturing operations, when the water that is used to fracture the underground formation is recovered from the well, prior to the well being put into production.  When it flows back to the surface to be recovered, that water is accompanied by natural gas.  Some companies vent that natural gas.  The new rules will require companies to conduct "reduced emissions completions" in which they recover that natural gas whenever recovery is feasible.  The new rules will require that companies send the natural gas to a flare for combustion whenever recovery is not feasible.  Either way — whether the natural gas is recovered or flared — the emissions of VOCs will be lower than if the natural gas were vented.    

A couple of states already require reduced emissions completions, but industry representatives expressed concern about immediate implementation of a nationwide rule.  Specifically, industry has stated that the type of equipment used to conduct reduced emissions completions does not exist in sufficient quantity for all the wells that are being hydraulically fractured nationwide, and that immediate implementation of a nationwide rule would bring drilling operations to a halt in some places.  Industry urged that the effective date of the reduced emissions requirement be delayed so that a sufficient quantity of the necessary equipment can be built. 

In response to that concern, the EPA is delaying until January 1, 2015 the requirement that companies recovery the natural gas whenever feasible.  In the meantime, however, companies will be required to flare the natural gas if they do not recover it.  Thus, the emissions of VOCs still will be reduced.  The requirement that companies flare the natural gas (if they do not recover it), along with portions of the new rules that apply to aspects of oil and gas activity other than hydraulic fracturing, will go into effect 60 days after the rules are published in the Federal Register.  That publication should occur soon.

For additional, information, see:

Hydraulic Fracturing and Earthquakes: British Government Releases Report

The British government has released a report regarding potential links between hydraulic fracturing and two minor earthquakes that occurred in the Blackpool area in April and May 2011.  The report, prepared for the Department of Energy and Climate Change, states that hydraulic operations by Caudrilla Resources likely caused the two small earthquakes, which had magnitudes 2.3 and 1.5, but that measures can be taken to prevent a recurrence of such "induced seismic activity" in the future.  The report stated that hydraulic fracturing should be allowed to proceed in the area, conditioned on the use of additional monitoring equipment.    

An earlier report likewise concluded that the earthquakes likely were caused by hydraulic fracturing operations conducted by Cuadrilla.  That earlier report concluded that "an unusual combination of factors" had made it possible for hydraulic fracturing to induce earthquakes, and that the combination of factors was unlikely to occur again.  The unusual circumstances included the fact that the fracturing operations were being conducted in a location that led to injections being made directly into a fault zone. 

The newly-released report, dated April 2012, states that "it is not possible to state categoriclly that no further earthquakes will be experienced" if a "nearby" well is fractured beause knowledge about the underground fault system in that area is "poor."  The new report stated, however, that the lack of information regarding faulting in the area possibly could be corrected by using 3-D seismic mapping.  The new report also concluded that it is unlikely that any additional earthquakes large enough to cause structural damage will occur even if fracturing is resumed in the area.

The conclusion that it took a set of highly unusual circumstances for fracturing to cause the earthquakes seems to be confirmed by U.S. experience.  In the United States, hundreds of thousands of fracturing jobs have been performed and rarely have they been suspected of causing seismic activity.  On several occasions, it has been suspected that the operation of wastewater disposal wells has induced seismic activity in the U.S., but wastewater disposal wells are operated different than hydraulically fractured oil and gas wells.  Some of the most famous earthquakes that are suspected of having been caused by human activity occurred near Denver in the 1960s, where the Army was using an injection disposal well to discard wastewater from the Rocky Mountain Arsenal.

For additional information from Britain, see the British government's webpage that invites comments on the new report and provides background factsheets on shale gas and induced seismicity.  For prior blog posts on this issue, see the Oil & Gas Law Brief posts dated April 16, 2012, March 13, 2012, and January 9, 2012.

Arkansas Oil & Gas Commission's Hydraulic Fracturing Regulations Receive High Marks in Independent Review

The non-profit, multi-stakeholder organization State Review of Oil and Natural Gas Environmental Regulations, Inc. ("STRONGER") conducted a review of the Arkansas Oil & Gas Commission's program for regulating hydraulic fracturing and published its conclusions earlier this year.  Overall, STRONGER's report gave the program an excellent review.

STRONGER's report, published in February 2012, stated that "the Arkansas program is well managed and professional and generally meets the 2010 Hydraulic Fracturing Guidelines" published by STRONGER.  The report identified the following strengths of the Arkansas program:

  • Updated Rules -- "Arkansas was among the first states in the nation to establish a system for the public disclosure of chemicals used in hydraulic fracturing operations." 
  • Well Water Complaint Protocol -- "The [Arkansas Oil and Gas Commission] has developed a water well complaint protocol that guides staff ... .  This well developed guidance document could serve as an example to other states." 
  • Website -- "The AOGC web site contains a wealth of information on hydraulic fracturing of gas wells in Arkansas."  Further, "[t]he web site is user friendly and educational."

The STRONGER team that reviewed the Arkansas program also made 3 specific recommendation for improving the program: (1) amend its regulations to require operators to provide notification to regulators prior to the start of fracturing so that regulators can monitor hydraulic fracturing operations; (2) secure permanent funding for four field inspector positions that are now supported with temporary (two year) funding; and (3) secure additional funding to increase field staff.

The STRONGER review included the submission of written questions, as well as site visits to the Arkansas Oil and Gas Commission.  The STRONGER review team consisted of seven members, including representatives from industry, environmental interests, and regulators from other states.

STRONGER's website also contains reports that review the oil and gas regulations of several other states.

USGS Scientists Say Increase in Earthquakes Not Linked to Hydraulic Fracturing

U.S. Geological Survey scientists say that an increase in the frequency of earthquakes is likely caused by human activity, but not by hydraulic fracturing.  Instead, they state that injection disposal wells are the likely culprit.  The fact that human activity might be causing a statistically relevant increase in seismic events might be relatively new news, but the fact that injection wells can cause seismic activity is not.  Geologists have been saying that for decades.

The possibility that humans are causing seismic activity has generated significant attention recently, in part because hydraulic fracturing is a popular news topic and many media sources erroneously have reported that scientists believe hydraulic fracturing is to blame for an increase in earthquakes. 

The latest series of erroneous reports began circulating after publication of the abstract of a paper that a USGS scientist will present this week at a meeting of the Seismological Society of America.  Although the abstract never mentions hydraulic fracturing, and instead plainly states that earthquakes may be linked to "waste water injection wells," a Department of Interior official felt compelled to issue a statement after a series of inaccurate media reports erroneously indicated that the USGS had linked earthquakes and hydraulic fracturing.  

As the official described it, "a number of news articles started popping up," and "[u]nfortunately ... the accuracy of the news reports varied greatly."  The official explained that USGS scientists have found the U.S. mid-continent area has seen an increase in seismic activity, and that the increase is "likely" caused by human activity, but:

USGS's studies do not indicate that hydraulic fracturing, commonly known as "fracking," causes the increased rate of earthquakes.  USGS's scientists have found, however, that at some locations the increase in seismicity coincides with the injection of wastewater in deep disposal wells."

And to make sure there was no confusion this time, he repeated himself, stating:

We also find that there is no evidence to suggest that hydraulic fracturing itself is the cause of the increased rate of earthquakes."

The statement notes that wastewater is a by-product of oil and gas activity.  Operators often dispose of that water in wastewater injection wells, but other types of wastewater also are discarded in injection disposal wells.  Indeed, one of the earliest examples of earthquakes apparently being caused by the operation of an injection well occurred in the 1960s near Denver, where the U.S. Army was disposing of wastewater at the Rocky Mountain Arsenal. 

Further, even within the oil and gas industry, the use of injection disposal wells is not limited to use in servicing oil or gas wells that have been hydraulically fractured.  Even for a conventional oil or gas well that is not hydraulically fractured, wastewater typically is produced as a by-product because the liquid that is produced from the well contains some water, and is not exclusively oil and gas.  This co-production of water and oil or gas occurs because the underground formations that contain oil and gas also contain water, and some of that water often is produced along with the oil and gas.  The most common way to dispose of such "produced water" is by underground injection. 

If a well is hydraulically fractured, there is an additional source of wastewater.  Much of the water that is used to fracture the well is recovered as "flowback" water before the well is put into production.  Flowback water also is often discarded by use of underground injection wells.  

In discussing the increase in earthquakes in the mid-continent area, the Department of Interior official stated: "These earthquakes are fairly small -- large enough to have been felt by many people, yet small enough to rarely have caused damage."

One of the most recent earthquakes that is believed to have been caused by operation of an injection disposal well occurred on December 31, 2011 near Youngstown, Ohio.  In the past, authorities have suspected that injection disposal wells have caused earthquakes in Arkansas, Colorado, Oklahoma, and Texas.

The USGS website contains a page with answers to frequently asked questions on this subject.

Obama Creates Interagency Working Group to Coordinate Federal Policy Regarding Natural Gas Development

Yesterday, President Barack Obama issued an executive order creating an interagency working group to coordinate federal government policies relating to natural gas development.  The executive order states that natural gas "production creates jobs and provides economic benefits to the entire domestic production supply chain, as well as the chemical and other manufacturers, who benefit from lower feedstock and energy costs."  Further, "with appropriate safeguards, natural gas can provide a cleaner source of energy than other fossil fuels." 

For these reasons, it is vital that we take full advantage of our natural gas resources, while giving American families and communities confidence that our natural and cultural resources, air and water quality, and public health and safety will not be compromised."

The new group, called the "Interagency Working Group to Support Safe and Responsible Development of Unconventional Domestic Natural Gas Resources," will be chaired by the Director of the Domestic Policy Council.  Other members will include representatives from:

(1) the Department of Defense;

(2) the Department of the Interior;

(3) the Department of Agriculture;

(4) the Department of Commerce;

(5) the Department of Health and Human Services;

(6) the Department of Transportation;

(7) the Department of Energy;

(8) the Department of Homeland Security;

(9) the Environmental Protection Agency;

(10) the Council of Environmental Quality;

(11) the Office of Science and Technology Policy;

(12) the Office of Management and Budget;

(13) the National Economic Council; and

(14) such other agencies or offices as the group's chair may invite to participate. 

Pennsylvania Supreme Court Agrees to Hear Butler case and Resolve Dispute Over Right to Produce Shale Gas

On April 3, the Pennsylvania Supreme Court agreed to hear a case in which the parties dispute whether a deed that reserves the right to produce "minerals and Petroleum Oils" has the effect of reserving the right to produce natural gas from the Marcellus Shale. 

Until a few months ago, many legal observers would have thought that such a deed clearly did not reserve the right to produce shale gas (natural gas produced from a shale formation), but a Pennsylvania appellate court ruled in September 2011 that such language in a deed from the late 1800s was unclear, and that expert testimony or other evidence regarding the intent of the parties to the deed would be needed.  That case, Butler v. Charles Powers Estates, 29 A.3d 35 (Pa. App. Ct. 2011), created an uproar in oil and gas circles and generated confusion about who owns the right to produce shale gas in circumstances in which similar  language has been used in deeds.

The dispute arose recently, but the seeds for the dispute were planted more than a century ago.  In 1881, the Estate of Charles Powers sold a tract of land to Patrick Fitzmartin, reserving the right to one-half of all "minerals and Petroleum Oils" produced from the property.  In Butler, the heirs to the Estate of Charles Powers and the successors to Mr. Fitzmartin dispute whether the Powers heirs have any right to shale gas produced from the property.

Based on a straightforward, three-step analysis, most oil and gas lawyers would have thought that the heirs did not have any such right.  That reasoning goes as follows.  First, in Pennsylvania, as in most states, the landowner generally has the right to produce and keep such substances as coal, oil, and natural gas from beneath his land.  Thus, the Estate of Charles Powers relinquished its right to shale gas when it sold the land, unless the reservation of the right to one half of "minerals and Petroleum Oils" changes the result.

Second, although a person who sells land can reserve the right to substances produced from the land, the Pennsylvania Supreme Court previously had held that the right to produce "minerals" generally does not include the right to produce natural gas.  See Highland v. Commonwealth, 161 A.2d 390 (Pa.), cert. denied, 81 S. Ct. 234 (1960); see also Dunham v. Kirkpatick, 101 Pa. 36 (1882) (the right to produce "all minerals" generally does not include the right to produce oil).

Third, the Pennsylvania Supreme Court previously had held that the right to produce "oil" does not include the right to produce natural gas.  See Bundy v. Myers, 94 A.2d 724, 725 (Pa. 1953).  Thus, the right to produce "minerals and Petroleum Oils" would not include the right to produce natural gas.  

Based on such reasoning the Butler trial court ruled in favor of the successors to Fitzmartin and against the Powers heirs, ruling that the Powers heirs did not have a right to one-half the shale gas produced from the property.  But the appellate court ruled that the reservation of the right to one-half of "minerals and Petroleum Oils" was ambiguous.  Accordingly, the appellate court reversed the judgment for the Fitzmartin heirs and remanded the case to the trial court for testimony regarding the intent of the parties to the 1881 deed.

The appellate court based its reasoning in part of the fact that, in Pennsylvania, the right to produce coal generally includes the right to produce methane contained within the coal.  See U.S. Steel Corp. v. Hoge, 468 A.2d 1380 (Pa. 1983).  The methane found in coal often is attached tightly to the coal, but the methane can be produced by the use of such "unconventional" processes as hydraulic fracturing and dewatering of the coal. 

The appellate court reasoned that, similarly, shale gas (which is mostly methane) is bound tightly within the shale, but can be produced by the unconventional process of hydraulic fracturing.  Thus, concluded the appellate court, perhaps the right to produce natural gas from the Marcellus Shale should belong to the person who owns the right to the produce the shale, and perhaps shale should be classified as a "mineral."  If so, the Powers heirs would have the right to one-half of the shale gas produced from the land because they own the right to one-half the "minerals."  Thus, the issue becomes whether shale is a "mineral," and if so, whether the right to produce "minerals" includes the right to produce gas within the minerals.

Whatever the merits of shale gas being treated like coalbed methane, many oil and gas lawyers lamented that the appellate court's decision in Butler was unexpected and would have an unfortunate result.  Namely, the decision would create uncertainty about who owns the right to produce natural gas from shale whenever there is a deed that grants someone the right to produce "minerals" (unless the deed also happened to expressly grant the right to produce natural gas to the same person who has the right to produce "minerals").

Such uncertainty could discourage drilling on property affected by deeds referring to the right to produce "minerals" and lead to expensive litigation about who owns what rights.  It is fortunate that the Pennsylvania Supreme Court has agreed to resolve the issue.  A decision by the Pennsylvania Supreme Court is likely to be several months away.

Additional EPA Testing Shows Water in Dimock is Safe

On Friday, the United States Environmental Protection Agency released the results of its testing of tap water samples from 20 homes in Dimock, Pennsylvania, and those results show that the water is safe.  The EPA previously had released test results from 11 other homes in Dimock, and those earlier results also showed that the water is safe.  Friday's announcement makes a total of 31 homes whose water has been tested by the EPA and shown to be safe. 

The EPA began its testing program because some residents complained about the quality of their water and blamed natural gas exploration and production activities, including hydraulic fracturing, for the alleged problem.  EPA made its announcement regarding its testing of water from the first 11 homes on March 15, 2012.  That announcement stated that the EPA had tested the water for several contaminants and had found that the "concentrations were all within the safe range for drinking water." 

The EPA's most recent announcement, released on Friday, April 6, discussed the sampling from the 20 additional homes, stating, "This set of sampling did not show levels of contaminants that would give EPA reason to take immediate action."

Cabot Oil & Gas, the company that operates in the area, released the following statement on Friday:  

Today, the US Environmental Protection Agency released the second set of water samples compiled at private drinking water wells in Dimock Pa.  This data confirms the earlier EPA finding that levels of contaminants found do not possess a threat to human health and the environment.  The EPA data is consistent with literally thousands of pages of water quality data accumulated by state and local authorities and by Cabot." 

 A page on an EPA website contains links to the test results for the water from all 31 homes, as well as a glossary of terms used in the test report, and information about "trigger levels" referenced in the report. 

 

Hydraulic Fracturing: Deadline for New Air Rules Delayed

Earlier this week, the EPA announced a two-week extension -- until April 17, 2012 -- in its deadline to finalize new regulations that are designed to minimize emissions of volatile organic compounds (VOCs) during hydraulic fracturing operations.  The new regulations are required under the terms of a February 2010 consent decree by which the EPA settled litigation brought against it in early 2009 by Wildearth Guardians, which sought to force the EPA to implement new air regulations to govern oil and gas activities. 

In the EPA's announcement, issued on April 2, the EPA stated that it and Wildearth agreed to the extension, which the EPA requested in order to have "additional time to fully address the issues raised in the more than 156,000 public comments we received on the proposed rules."  The original deadline for EPA to issue proposed rules was January 31, 2011, and its deadline to issue final rules was November 30, 2011, but those deadlines were extended multiple times, with the EPA ultimately issuing proposed regulations on July 28, 2011.

As the Oil & Gas Law Brief discussed in more detail on August 10, 2011, the proposed regulations would require companies to engage in so-called "green" or "reduced emissions" completions during the flowback portion of hydraulic fracturing operations.  During that step of the process, the water that has been used to fracture the underground formation is recovered from the well by allowing the natural gas in the underground formation to push the water back to the surface.  Sometimes companies have vented the natural gas that accompanies water to the surface, resulting in the release of VOCs to the atmosphere.  The EPA's new regulations generally would prohibit such venting, requiring that companies recover the gas when feasible and flare the gas when recovery is not feasible. 

The new regulations also include provisions that seek to lower emissions from natural gas compressors, pneumatic controllers, natural gas processing plants, and crude and condensate storage tanks.  At the time EPA proposed the regulations, it also issued a slide presentation regarding the proposed rules and a "Fact Sheet" regarding the proposal.

Supreme Court's Sackett Opinion Prompts EPA to Drop Case Against Range Resources

Last Friday, the United States Environmental Protection Agency withdrew a compliance order it previously had issued to Range Resources, and also dismissed an action the Agency had filed against Range in federal court.  The EPA's retreat appears to have been prompted by the Supreme Court's unanimous decision against the Agency the week before in Sackett v. Environmental Protection Agency.

The case against Range arises out of complaints by the owners of two water wells in Parker County, Texas, which is in the Dallas/Fort Worth area.  After receiving complaints from the well owners about the quality of their water, the EPA conducted an investigation and concluded that Range's oil and gas operations might have caused contamination of the two water wells with benzene and methane.  Relying on certain emergency powers granted to the EPA by the Safe Drinking Water Act, the EPA ordered Range to do various things, including supplying the owners of the water wells with a replacement water supply and undertaking a long term remediation project.  The EPA issued the compliance order without holding a hearing.

Range complied with certain aspects of the order, such as supplying the well owners with an alternative source of water, but Range contended that it had not caused the alleged contamination.  Range declined to comply with other aspects of the compliance order and requested a hearing.  The EPA refused to grant a hearing and threatened to fine Range tens of thousands of dollars per day if Range did not comply with all aspects of the compliance order.  The EPA contended that the law did not give Range the right to a hearing regarding the compliance order, even though EPA asserted that Range could face large fines if it did not comply with the order. 

When Range did not promptly agree to comply with all portions of the order, EPA brought an action against Range in the United States District Court for the Northern District of Texas.  Two days later, Range brought an appeal of the EPA's actions to the United States Fifth Circuit Court of Appeals, seeking review of the EPA's compliance order and the Agency's refusal to grant a hearing.  The district court stayed the EPA's action, pending resolution of Range's appeal to the Fifth Circuit.  The Fifth Circuit held oral argument on the appeal in October 2011 and the case has pending before the appellate court since then.

The EPA's contention that Range was not entitled to a hearing was similar to the contentions made by the EPA in Sackett.  The Sacketts are a couple who planned to build a home on a residential lot they own in Bonner County, Idaho.  The lot is near Priest Lake, though several other lots that contain permanent structures are located between the lake and the Sacketts' property.  After the Sacketts filled in part of their lot with dirt and rock in preparation for construction, the EPA issued an administrative compliance order that purported to require the Sacketts to do several things, including restoring the lot to its original condition.  The compliance order stated that the lot was a "wetland," and that the Sacketts' pre-construction activities violated wetlands regulations enacted pursuant to the Clean Water Act.

The Sacketts requested a hearing in which they could contest whether their property should be classified as a wetland.  And it is conceivable that the Sacketts would have prevailed in such a hearing, if the EPA had agreed to grant a hearing.  An Supreme Court Justice Alito has noted, "[t]he reach of the Clean Water Act is notoriously unclear."  Nevertheless, the EPA denied the Sacketts' request for a hearing and threatened to fine them $75,000 per day if they did not obey the compliance order ─ $37,500 for the alleged Clean Water Act violation and an additional $37,500 for not obeying the EPA's compliance order. 

The Sacketts brought a petition for review with the United States Court of Appeals for the Ninth Circuit, but that court sided with the EPA, which argued that the Sacketts were not entitled to a hearing to challenge the compliance order.  The United States Supreme Court agreed to review the case, and a unanimous Court agreed with the Sacketts that they were entitled to a hearing.  Justice Scalia wrote for the Court, and both Justice Ginsberg and Justice Alito wrote concurring opinions.  Justice Alito noted that the EPA's assertion that no one is entitled to a hearing challenging a compliance order "would have put the property rights or ordinary Americans entirely at the mercy of Environmental Protection Agency (EPA) employees."  He stated, "In a nation that values due process, not to mention private property, such treatment is unthinkable." 

The Court's opinion and the two concurring opinions were issued on March 21, 2012.   The next day, the Department of Justice sent a Rule 28(j) letter to the United States Fifth Circuit, informing it of the Supreme Court's decision in Sackett.  A week later, on March 29, the EPA withdrew the compliance order it had issued to Range, and the day after that the EPA voluntarily dismissed the action it had filed against Range in the Northern District of Texas.  The EPA's withdrawal of the compliance order and its dismissal of its district court action made Range's appeal to the Fifth Circuit moot, so Range dismissed the appeal on March 30.

As Justice Alito noted in his opinion, the Court's opinion in Sackett is a step forward, but real relief will require Congressional action to clarify the Clean Water Act.  Although individuals now will be entitled to a hearing to contest the EPA's issuance of a compliance order, persons still could face substantial fines if the EPA prevails in proving that someone has breached Clean Water Act regulations (and the same is true for the Safe Drinking Water Act violations).  Further, the Clean Water Act is ambiguous enough that it is impossible to know in advance the ultimate success of any challenge to an EPA determination that someone has violated the Act.  That uncertainty, combined with fines that can amount to tens of thousands of dollars for each day of noncompliance, guarantees that most Americans will not be able to risk challenging an EPA action.  Most persons who receive a compliance order will have little choice but to obey the order, rather than risk the financial disaster that could result from an unsuccessful challenge.  As Justice Alito described the situationin Sackett:

The Court's decision provides a modest measure of relief.  At least, property owners ... will have the right to challenge the EPA's [compliance orders].  But the combination of the uncertain reach of the Clean Water Act and the draconian penalties imposed for the sort of violations alleged in this case still leaves most property owners with little practical alternative but to dance to the EPA's tune."

Environmental Groups Sue for Release of Hydraulic Fracturing Fluid Information

A group of four environmental organizations filed suit late Friday against the Wyoming Oil & Gas Conservation Commission, seeking release of information identifying certain substances contained in hydraulic fracturing fluids used in Wyoming. 

The information sought by the plaintiffs previously was submitted to the Commission by various companies that provide hydraulic fracturing services to the oil and gas industry.  Those companies submitted the information pursuant to state regulations that require the companies to disclose to the Commission on a well-by-well basis all chemicals used for hydraulic fracturing operations in Wyoming.   Wyoming enacted the mandatory disclosure requirement in 2010, making it the first state to impose such a requirement.  Since then, several other states have enacted similar provisions. 

Wyoming's regulations provide that the information disclosed to regulators generally will become public information, but that a company disclosing information may request that the identity of specific substances used in fracturing fluids not be disclosed to the public if those substances constitute trade secrets.  If the Commission accepts a trade secret claim, the substance that constitutes a trade secret does not become public information, while the remainder of the ingredients used in the fracturing fluid are disclosed. 

At the time Wyoming enacted its mandatory disclosure requirement, some environmentalists expressed concern that companies would make wholesale and across the board claims that the composition of fracturing fluid constituted trade secrets.  That has not happened, but the Commission has approved approximately 50 trade secret requests made by companies in 2010 and 2011 for specific ingredients.  Traditionally, companies that perform hydraulic fracturing have attempted to keep the composition of their fracturing fluid confidential in order to maintain their competitive advantage against other companies. 

In a press release issued yesterday, the plaintiffs assert that they sent a public records request to the Wyoming Oil & Gas Conservation Commission in November 2011, asking that the Commission disclose the identity of substances that the Commission previously had recognized as trade secrets.  The Commission declined.  The environmental organizations responded by filing suit on Friday, March 23, 2012 in the Seventh Judicial District Court for the State of Wyoming, in the County of Natrona.  The plaintiffs allege in their petition that the Commission approved "nearly all" trade secret requests submitted to the Commission, even though companies allegedly provided insufficient information to justify their trade secret requests or sought trade secret status for substances that do not qualify as trade secrets.

To evaluate whether information qualifies as a "trade secret," several factors generally are considered, including the number of people who know the information and what efforts a company has made to keep the information confidential. 

The plaintiffs include the Powder River Basin Resource Council, Wyoming Outdoor Council, Earthworks, and OMB Watch.  The suit, styled Powder River Basin Resource Council, et al. v. Wyoming Oil and Gas Conservation Commission, was filed by Earthjustice, a nonprofit environmental law firm.

Ohio Officials Say Injection Disposal Well Caused Earthquakes

A few days ago, the Ohio Department of Natural Resources issued a preliminary report concluding that the operation of an injection disposal well caused a series of earthquakes that occurred near Youngstown, Ohio in late 2011.  Ohio officials ordered that the injection well at issue, the Northstar One Class II Injection Well, be shut down in late 2011, after officials began to suspect that the well might be inducing the seismic activity near Youngstown, which ranged from 2.1 to 4.0 on the Richter scale. 

In a statement, Ohio DNR noted that injection disposal wells occasionally have been linked to earthquakes in the past, but that such links are "extremely rare."  The statement noted that "[t]here are more than 144,000 operational Class II disposal wells in the United States, but only six have been linked to earthquakes."  In its report, Ohio DNR added: 

Geologists believe it is very difficult for all conditions to be met to induce seismic events.  In fact, all the evidence indicates that properly located Class II injection wells will not cause earthquakes.  To induce an earthquake a number of circumstances must be met: 

  • A fault must already exist within the crystalline basement rock;
  • That fault must already by in a near‑failure state of stress;
  • An injection well must be drilled deep enough and near enough to the fault and have a path of communication to the fault; and
  • The injection well must inject a sufficient quantity of fluids at a high enough pressure and for an adequate period of time to cause failure, or movement, along that fault (or system of faults)."

Ohio DNR states that the Northstar One Class II Injection Well was drilled near a previously unmapped fault.  To prevent similar problems from occurring in the future, Ohio DNR announced plans to reform its injection well regulations in several ways.  For example, Ohio DNR will prohibit all future drilling into the Precambrian basement rock into which the Northstar One Injection Well was drilled.  The new regulations also will require officials to review existing geological data for known fault areas within the state, and will require that new injection disposal wells avoid those areas. 

In addition, Ohio DNR will begin requiring that operators of disposal wells make various geophysical measurements.  For example, operators will be required to measure the pressure of the injection reservoir prior to starting injections, to continuously monitor the formation's pressure during injections, and to provide an electronic feed of those results to Ohio DNR for its review.  Further, Ohio DNR will require that operators of injection wells install automatic shutoff systems that will halt injections if fluid injection pressures exceed a maximum level set by the agency.

Last year, much of the media linked the seismic activity near Youngstown to hydraulic fracturing, but the NorthStar One Injection Well is not a hydraulically fractured well.  Instead, it is an injection disposal well that is used for the disposal of waste fluids.  The Northstar One Class II Injection Well happened to be used for the disposal of hydraulic fracturing wastewater, but Class II injection wells also are used for the disposal of other types of wastewater from oil and gas operations, and other classes of injection wells are used for the disposal of liquid wastes from sources other than the oil and gas industry.  There has not been any suggestion that the disposal of hydraulic fracturing wastewater via underground injection is any more prone to inducing seismic activity than the disposal of other types of fluids via underground injection.

In addition to the information in its press release, Ohio DNR provided a document with answers to frequently asked questions, a copy of the executive summary of its preliminary report on the Northstar One Class II Injection Well and the seismic events near Youngstown, Ohio, and a copy of the full preliminary report.

For additional information on injection disposal wells inducing seismic activity, and whether hydraulic fracturing can induce seismic activity, see Frack Quakes?  Can Hydraulic Fracturing Really Cause Earthquakes?, Oil & Gas Law Brief, January 9, 2012.

New York Court Upholds Town of Middlefield Ban on Hydraulic Fracturing and other Oil and Gas Activity

On Friday, February 24, a New York court upheld a Town of Middlefield zoning ordinance that bans all oil and gas activity, including hydraulic fracturing, throughout the Town's jurisdiction.  The ruling was the second in four days upholding such a ban, as it followed a court ruling on February 21 that upheld a similar ban by the Town of Dryden (see February 22 post in Oil & Gas Law Brief).

The Town of Middlefield enacted the ban in June 2011.  Although reports at the time indicated that the supporters of the ban were motivated in large part by opposition to hydraulic fracturing, the ordinance prohibits all oil and gas activity, whether or not it involves fracturing.  The ban was soon challenged by Cooperstown Holstein Corporation, which had granted two oil and gas leases a few years before, and which hoped that the leaseholder would drill on the leased land.  Cooperstown Holstein argued that the local ban on oil and gas activity was preempted (made unenforceable) by a state oil and gas statute, New York Environmental Conservation Law § 23-0303, which states:

The provisions of this article shall supersede all local laws or ordinances relating to the regulation of the oil, gas and solution mining industries ... ."

In a case decided in the early 1980s, a New York court held that the statute preempted a local zoning ordinance that would have prohibited the drilling of any oil or gas well within that Town unless the company paid a $25 permit fee and posted a $2500 bond.  See Envirogas v. Town of Kiantone, 447 N.Y.S.2d 221 (N.Y. Sup.), aff'd, 454 N.Y.S.2d 694 (N.Y.A.D.), appeal denied, 458 N.Y.S.2d 1026 (N.Y. 1982).

The court that heard the challenge to the Town of Middlefield's ban agreed that the statute attempts to achieve uniform rules for the oil and gas industry statewide by preempting local laws which "regulate" the oil and gas industry, but the court concluded that a zoning ordinance prohibiting oil and gas activity in certain locations is not what ECL § 23-0303 means by "regulation."  The court stated in its written decision that, after consulting dictionary definitions of "regulation" and the legislative history of New York's Environmental Conservation Law, the court was convinced that

[T]he legislature's intention was to insure state-wide standards to be enacted by the Department of Environmental Conservation as it related to the manner and method to be employed with respect to oil, gas and solution drilling or mining, and to insure proper state-wide oversight of uniformity ... .  Clearly, the state's interests may be harmonized with the home rule of local municipalities in their determination of where oil, gas and solution drilling or mining may occur.  The state maintains control over the 'how' of such procedures while the municipalities maintain control over the 'where' of such exploration."

The judge was Donald F. Cerio, Jr.  His reasoning was similar to that of the court which upheld the Town of Dryden's ban on oil and gas activity a few days before.

Other states also have seen court battles over whether state oil and gas laws designed to achieve uniform regulations preempt local zoning ordinances that seek to prohibit oil and gas activity throughout a jurisdiction or in certain portions of it.  In some cases, courts have held that local bans are preempted by state law and in some cases courts have upheld local laws.  Examples of cases holding that zoning ordinances regulating the location of oil and gas activity are preempted by state oil and gas laws include a ruling last year that a ban enacted by the City of Morgantown, West Virginia was preempted, and a ruling several years ago that a zoning ordinance by the City of Shreveport, Louisiana that attempted to ban drilling within the vicinity of a lake was preempted.

New York Court Rules Town of Dryden Ban on Oil and Gas Activity is Not Preempted by State Law

A trial court in New York ruled yesterday that the Town of Dryden's ban on oil and gas activity is not preempted by state law.  The case turned on interpretation of ECL §  23-0303, a section of New York's state statutes governing oil and gas activity.  Section 23-0303 states:  

The provisions of this article shall supersede all local laws or ordinances relating to the regulation of the oil, gas and solution mining industries; but shall not supersede local government jurisdiction over local roads or the rights of local governments under the real property tax law."

The dispute arose after the Town of Dryden enacted a zoning ordinance last year that banned all oil and gas activity within the Town's jurisdiction.  Although the ordinance bans all oil and gas activity, the supporters of the ban primarily were motivated by opposition to the possible use of hydraulic fracturing to produce natural gas from the Marcellus Shale, which lies beneath the Town of Dryden. 

The ban was challenged in court by Anschutz Exploration, which had invested $5.1 million and acquired mineral leases covering 22,200 acres within the Town's jurisdiction prior to the ban's enactment. Anschutz argued that the ban was preempted by ECL § 23-0303's provision that New York's state oil and gas laws "shall supersede all local laws or ordinances relating to the regulation of oil and gas."  Anschutz also noted that a prior case had ruled that ECL § 23-0303 preempted a zoning ordinance enacted by the Town of Kiantone that would have prohibited the drilling of any oil or gas well within that Town unless the company paid a $25 permit fee and posted a $2500 bond.  See Envirogas v. Town of Kiantone, 447 N.Y.S.2d 221 (N.Y. Sup.), aff'd, 454 N.Y.S.2d 694 (N.Y.A.D.), appeal denied, 458 N.Y.S.2d 1026 (N.Y. 1982).

But the judge in Anschutz Exploration Company v. Town of Dryden ruled that Dryden's total ban was not preempted.  Judge Phillip R. Rumsey stated that, by referring to "regulation of oil and gas," the state statute means regulation of operational details.  He analogized ECL § 23-0303 to New York's Mined Land Reclamation Law, ECL § 23-2703, which New York's top court has held does not preempt zoning laws.  Judge Rumsey relied on the fact that the Reclamation Law statute has language similar to the language in ECL § 23-0303 regarding superseding all local laws.  Given that similarity and the fact that the Reclamation Law has been interpreted as not preempting local zoning laws, Judge Rumsey reasoned that ECL § 23-0303 must not preempt local zoning laws. 

But the two statutes also have differences that arguably undermine Judge Rusmey's reasoning that the preemptive effect of the statutes must be the same.  For example, the Reclamation Law expressly states that it does not prohibit "local zoning ordinances."  Section 23-0303, the New York oil and gas statute dealing with preemption, contains no such language.  The closest thing that the oil and gas statute has to that type of language is a provision stating that the statute does not supersede "local government jurisdiction over local roads."  But the Town of Dryden ordinance is an outright ban on oil and gas activity, and is not written as a regulation of roads.  Judge Rumsey addressed this fact by suggesting that, although the ban is not expressly written as a regulation of roads, the ban nevertheless is not preempted because oil and gas companies use local roads to transport their equipment and supplies.

A link to a copy of the ruling is here.

New Report Finds that Hydraulic Fracturing Itself Poses Little Risk to Groundwater

The University of Texas Energy Institute released a report on hydraulic fracturing yesterday at a meeting of the American Association for the Advancement of Science.  The report concludes that there have been no confirmed cases of groundwater contamination caused by the hydraulic fracturing process, and that hydraulic fracturing itself poses little risk to groundwater.  The report's conclusions include the following:

  • allegations of groundwater contamination frequently result from the presence of methane that is found naturally in the groundwater in many places, and the presence of methane in those circumstances is unrelated to oil and gas activity
  • there have been no documented cases of the hydraulic fracturing process itself causing groundwater contamination   
  • aspects of oil and gas activity other than hydraulic fracturing sometimes lead to contamination
  • the aspects of oil and gas activity that sometimes cause contamination include poor well construction (including the casing and cementing of wells), surface spills, and blowouts    
  • the oil and gas regulations of most states were written before shale gas development became common, and many of those regulations could use updating, and  
  • improvements could be made in casing and cementing regulations.

Yesterday, Scott Anderson of the Environmental Defense Fund wrote a blog post that discussed the report.  He began by acknowledging that the Environmental Defense Fund had been involved with shaping the Energy Institute's study.

The report’s conclusions are those of the authors, though Environmental Defense Fund (EDF) helped the University of Texas at Austin define its scope of work and reviewed drafts during the course of the project." 

He also acknowledged that prior inquires also have failed to find any confirmed examples of groundwater contamination that was caused by fracturing: "As has been the case in other inquiries, the University of Texas study did not find any confirmed cases of drinking water contamination due to pathways created by hydraulic fracturing." 

Mr. Anderson noted, however, that this does not mean that it is impossible for hydraulic fracturing to cause contamination.  He also discussed the report's conclusions that aspects of oil and gas activity other than hydraulic fracturing sometimes cause contamination, that "gaps" exist in the oil and gas regulations of some states, and that the regulations in many states should be updated.

The Energy Institute's report is called "Fact-Based Regulation for Environmental Protection in Shale Gas Development." 

National Ground Water Association Issues Position Paper on Hydraulic Fracturing

The National Ground Water Association (NGWA), a nonprofit group of groundwater professionals, recently issued a statement announcing that it has produced a position paper on hydraulic fracturing.  The position paper calls for further research regarding hydraulic fracturing, but also suggests that water conservation efforts and issues relating to aspects of oil and gas activity other than hydraulic fracturing are more significant than hydraulic fracturing itself.  The other aspects of oil and gas activity discussed by the position paper include steps in the well construction process, such as casing and cementing, and management practices relating to spill prevention.  The NGWA's position paper states:

NGWA recognizes that hydraulic fracturing of oil and gas wells is a mature technology and has been a widespread practice for many decades.  While no widespread water quality or quantity issues have been definitively documented that are attributable to hydraulic fracturing and related activities at oil and gas sites, there have been isolated cases where faulty casing installations (including poor cement bonds) or poor management of materials/chemicals at the surface are suspected as having negatively impacted groundwater, surface water, or water wells."

NGWA's position paper offers suggestions for groundwater and drinking water protection, and those suggestions similarly focus on aspects of oil and gas activity other than a possibility that hydraulic fracturing itself might cause groundwater contamination.  The NGWA's recommendations focus on

  • ensuring proper construction of oil and gas wells
  • monitoring of water usage rates
  • encouraging the investigation of the feasibility of using brackish water or other alternatives to fresh water for hydraulic fracturing
  • properly sealing any old, abandoned wells 
  • implementing best management practices to avoid spills
  • disclosure of the chemicals used in hydraulic fracturing 
  • testing of nearby waterwells before and after oil or gas wells are drilled (NGWA explained that, because certain chemicals associated with oil and gas activity sometimes are found naturally in groundwater, before and after testing of water wells could assist in resolving "future contamination complaints"), and
  • ensuring proper construction of water wells.

The NGWA's position paper is largely consistent with statements previously made in the Oil & Gas Law Brief, which has stated that issues relating to well construction, well control, and spill prevention merit more attention than hydraulic fracturing. 

Eagle Ford Task Force Concludes Carrizo Wilcox Aquifer Has Sufficient Water for Both Hydraulic Fracturing and Other Uses

A 26-member Eagle Ford Task Force appointed by Texas Railroad Commissioner David Porter has concluded that the Carrizo Wilcox Aquifer in South Texas contains enough water to support oil and gas activities, including hydraulic fracturing, in addition to supporting other uses. 

The Task Force met in San Antonio twice in late 2011 to discuss water usage issues relating to development of the Eagle Ford Shale.  Some people have expressed concern that the aquifer might not be capable of simultaneously supporting both traditional users of the aquifer and increased use for hydraulic fracturing, particularly given the drought conditions existing in Texas.  But in a press release dated January 26, 2012, Commissioner Porter stated,

I am pleased to announce, after exhaustive research, our task force has found water sourcing in South Texas is currently not an issue." 

He added, "We will continue to study best practices for water management in the region to help mitigate any future issues." 

Data presented to the Task Force indicates that 6% of water in South Texas is used for oil and gas activity in the Eagle Ford Shale, 64% if used for irrigation, and 17% is used for municipal purposes.  The press release stated that industry has reduced the amount of water used to hydraulically fracture wells from an average of 15 acre-feet per well (approximately 4.9 million gallons) to 11 acre-feet per well (approximately 3.6 million gallons). 

Texas has numerous local Groundwater Conservation Districts that monitor water levels monthly.  Task Force member Mike Mahoney, who serves as General Manager of the Evergreen Underground Water Conservation District, stated that they "have seen water levels drop this past year due to the drought," but that "we do not see groundwater pumping for oil and gas drilling and completions as a significant contribution to the decline in water levels, when compared to overall pumping."

The press release quoted Task Force member Teresa Carrillo, a member of the Executive Committee of the Sierra Club, Lone Star Chapter as expressing pleasure that industry has reduced water usage.  Ms. Carrillo expressed concern, however, that "pumping may have localized impacts on water levels in the aquifer and on aquifer discharges to stream and springs.  We are hopeful that through this task force process our concerns will be addressed." 

The Eagle Ford Task Force has plans to continue monthly meetings to discuss issues relevant to the region.

The Railroad Commission is the state agency that regulates oil and gas activity in Texas.

Hydraulic Fracturing News: EPA's Pavillion Report Will Receive Peer Review

A controversial EPA draft report regarding the possibility that hydraulic fracturing has affected groundwater near Pavillion, Wyoming finally will be receiving peer review.

EPA released the draft report to the public last month.  In it, the EPA discusses its study of groundwater in the vicinity of Pavillion and states the Agency's conclusion that hydraulic fracturing likely contributed to groundwater contamination near Pavillion.  The draft report generated substantial attention because, if the EPA's conclusions hold up, the report apparently would provide the first documentation of an instance in which hydraulic fracturing has affected groundwater.  The draft report also became controversial because many people raised significant questions about various aspects of the methodology used by the EPA in its Pavillion study and about the reasoning that went into the EPA's conclusions (see Oil & Gas Law Brief posts dated December 12 and December 26, 2011).

In addition, several people criticized the EPA for releasing the draft report before subjecting it to peer review.  As noted on the EPA's own website, the Office of Management and Budget issued a bulletin to federal agencies in 2004 directing that "important scientific information shall be peer reviewed by qualified specialists before it is disseminated by the federal government."  The bulletin explains that, "Peer review is one of the most important procedures used to ensure that the quality of published information meets the standards of the scientific and technical community."  The peer review process "can filter out biases" and "clarify assumptions."  Further, the process "may encourage authors to more fully acknowledge limitations and uncertainties."

The EPA did not subject its draft report to peer review before releasing it to the public.  In a statement to the press announcing release of the draft report, the EPA suggested, however, that the draft report would be subjected to peer review later.  The press statement did not discuss the nature or timing of the peer review process. 

The EPA has now provided some detail on an upcoming peer review of the Agency's Pavillion study and draft report.  EPA Administrator Lisa Jackson explained in a recent letter to Wyoming Governor Matthew Mead that the EPA plans to convene a panel of five to seven experts with expertise in relevant scientific and engineering disciplines to meet publicly and consider "charge questions" that will be posed to them regarding the Pavillion study.  The EPA will draft a proposed "charge" and solicit feedback regarding the draft from interested parties.  The expert panel will be selected by an EPA contractor, based on public nominations received during a 30-day nominating process.  The EPA has published a Federal Register notice soliciting nominations.  

Jackson's recent letter to Mead defends the EPA's conclusions, but notably, Jackson also states that the "causal link" between contamination and "fracturing has not been demonstrated conclusively" at Pavillion.  Further, in an apparent reference to the fact that hydraulic fracturing was performed at much shallower depths at Pavillion than in most shale formations, Jackson stated that the EPA's Pavillion "analysis is limited to the particular geologic conditions in the Pavillion gas field and should not be applied to fracturing in other geologic settings." 

The Agency made a similar observation in its press release announcing the release of the EPA's draft report.  That press release states that the fracturing near Pavillion was being performed at shallow depths, and that the depth of the Pavillion gas field actually overlaps that of an underground source of drinking water.  The press release went on to state that the EPA's conclusions are "specific to Pavillion" and that the Pavillion gas field has "production conditions different from those in many other areas of the country." 

The "Conclusion" section of the draft report similarly states that, "Hydraulic fracturing in the Pavillion gas field occurred into zones of producible gas located within an Underground Source of Drinking Water (USDW)."  The fracturing occurred, though, at depths greater than those to which domestic water wells are actually drilled.

Jackson's letter to Mead suggests that the letter was prompted by letters from Mead to Jackson in December 2011 and earlier in January 2012.

Fracking News: Cornell Professors Respond to Critique by Fellow Cornell Professors in Dispute Over Relative Greenhouse Gas Footprints of Shale Gas and Coal

In April 2011, Robert W. Howarth and two other professors from Cornell published a study in which they concluded that shale gas has a higher greenhouse gas ("GHG") footprint than coal.  Earlier this month, a different group of Cornell professors that included Lawrence Cathles published a study in which they conclude that Howarth's analysis is "seriously flawed" and that shale gas has a GHG footprint that is only one-third to one-half that of coal.  Now, Howarth and his original collaborators have responded with a paper that defends their original study.  So, how do Howarth and his co-authors respond to the criticisms leveled by Cathles?

One of Cathles' primary criticisms is that Howarth "significantly overestimate[]" the emissions of natural gas that occur during shale gas extraction.  Cathles asserted that a large portion of Howarth's overestimation results from his assumption that companies always vent the natural gas that accompanies water to the surface during flowback (see the January 16, 2012 post in the Oil & Gas Law Blog for a detailed discussion of what this assumption is all about and for more details regarding the Cathles article). 

Cathles states that, despite Howarth's assumption that companies always vent, the reality is that often companies do not vent during flowback.  Howarth concedes in his new paper that companies do not always vent, but he cites an EPA estimate that companies vent 85% of the time.  Howarth states that he could reduce his estimate of emissions by 15% to account for the fact that companies do not always vent, but given other uncertainties in the available data, he sees no reason to make that correction.

There is, however, a more significant problem with Howarth's assumption that companies always vent during flowback.  The EPA has published regulations that generally would prohibit venting altogether, and those regulations are scheduled to become final on April 3, 2012, a mere ten weeks from now.  Howarth's new paper acknowledges those proposed regulations, and the fact that the EPA estimates those regulations will cut emissions of natural gas during flowback by 95%. 

Howarth then states, however, that the proposed regulations will only require recovery of the natural gas when a pipeline connection is available.  Howarth's statement is true, but potentially misleading, because even when a pipeline connection is not available the regulations generally will prohibit venting.  In those circumstances, companies will be required to flare the natural gas unless doing so would present a safety risk, and the products of such flaring have a substantially lower GHG footprint than the natural gas that is flared.  Observers expect that the EPA's proposed regulations will go into effect as planned.  If that happens, Howarth's assumption that companies always vent will be a serious flaw in his analysis.

Cathles also criticized Howarth for his assumption that natural gas flows to the surface throughout flowback at the same rate that it flows after flowback is complete.  Cathles states that this assumption leads to an overestimation of gas flow because water that is present during flowback depresses the flow rate of natural gas, particularly at the beginning of flowback.  Howarth concedes that water significantly restricts the flow of natural gas in the initial portion of flowback, and even that the fluid flowing to the surface is all water at the very beginning of flowback.  He suggests that his assumption is justified because natural gas flows freely by the end of the flowback period.    

In addition, Cathles and his colleagues state that Howarth's study overestimated the amount of natural gas that leaks during storage, transmission, and distribution of the gas to market.   Howarth acknowledges that the estimates of leakage rates he used in his study are much higher than the EPA's estimates of leakage rates, but he states that he thinks the EPA's estimates are too low.  He asserts that the EPA's estimate of leakage rates are too low because the estimates are based on studies conducted at "model" facilities that he implies were younger than the facilities that often are used for natural gas storage and distribution.  

Cathles asserted that another flaw in Howarth's analysis is that he fails to account for the fact that natural gas-fired power plants are more efficient at converting heat energy to electricity than coal-fired plants.  Howarth's reply is that most natural gas is used for generating heat, rather than in generating electricity, and therefore it is appropriate to ignore the difference in efficiency between gas-fired and coal-fired power plants.  Howarth's response may be valid to the extent someone wants an estimate of the life cycle GHG footprint of shale gas when it is used for generating heat.  But a major issue that has been raised in public discussions is how the GHG footprints of natural gas and coal compare when they are used as fuels for the generation of electrical power, and for that comparison, an accurate consideration of the differences in power plant efficiencies is essential.  

Finally, Cathles and his colleagues stated that Howarth erred by using a 20-year time horizon rather than a 100-year time horizon.  This issues arises because a comparison of the relative GHG footprints of coal and shale gas requires consideration of both carbon dioxide and methane.  This requires selection of a particular time horizon because methane has a stronger GHG footprint than carbon dioxide, but methane breaks down in the atmosphere over time, whereas carbon dioxide accumulates in the atmosphere.  Howarth chose a 20-year time horizon for the main comparisons he made in his study, but Cathles and his colleagues state that a 100-year time horizon is more appropriate. 

Howarth concedes that researchers "quite commonly us[e] only the 100-year time frame."  Nevertheless, Howarth defends his use of a shorter time frame.  He states that some studies have estimated that the earth is about 18 yeas away from a "tipping point" in which rising temperatures would cause significant methane release from the melting of permafrost, which could reinforce a trend toward global warming.  Howarth states that this makes a short time horizon critical, even though the GHG footprint of methane is considerably lower when looking at longer time horizons.

In their new paper, Howarth and his colleagues state that they "stand by" their prior "analysis and conclusions," and that they believe that "most" of Cahtles' criticisms "have little merit."  Howarth's reply provides some interesting information, though some of his rebuttals are unconvincing.

Hydraulic Fracturing News: Latest Cornell Study Concludes that Greenhouse Gas Footprint of Shale Gas is Much Lower than that of Coal

Several months ago, a group of Cornell University professors led by Robert Howarth published an article stating that shale gas has a higher greenhouse gas (GHG) footprint than coal.  But subsequent studies reached the opposite result, concluding that shale gas has not just a lower, but a much lower GHG footprint than coal.  Now, a new study from Cornell University concludes that the earlier Cornell study by Howarth was "seriously flawed," and that shale gas has a GHG footprint that is only one-third to one-half that of coal.

The new Cornell study was conducted by L.M. Cathles III and others, who published an article online in the journal Climatic Change Letters on January 3, 2012.  The authors begin by noting certain facts that no one disputes.  First, shale gas burns much more cleanly than coal.  Unlike the burning of coal, the combustion of shale gas (natural gas produced from shale) does not produce sulfur, mercury, ash, and particulates. Further, on an energy equivalent basis, the burning of shale gas produces much less carbon dioxide than coal.  After noting these undisputed facts, Cathles and his colleagues discuss several errors made by Howarth ─ errors that led to his erroneous conclusion that shale gas has a large GHG footprint even though it burns so cleanly. 

First, Howarth and his collaborators "significantly overestimate[d] the fugitive emissions associated with unconventional gas extraction."  In large part, Howarth's overestimation of emissions is the result of  unrealistic assumptions regarding flowback.  "Flowback" is a step that occurs after hydraulic fracturing is complete, when operators allow the shale formation's pressure to push the hydraulic fracturing water back to the surface, where it is recovered.  Significant quantities of natural gas accompany the flowback water.  Howarth assumed that companies always vent that natural gas to the air.  And, because the principal component of natural gas is methane (a greenhouse gas), Howarth concluded that such venting causes shale gas to have a large GHG footprint.

But natural gas is a valuable product and many companies recover and sell that natural gas, rather than venting it.  Sometimes it is not possible to recover and sell the gas because a pipeline connection is not yet available, but in those circumstances companies often flare the gas, rather than venting it, because it would be a safety hazard to vent such a large amount of natural gas at the well site.  Indeed, as previously noted in the Oil & Gas Brief, some states require companies to recover or flare that gas, rather than venting it (the combustion products have a much lower GHG effect than the natural gas itself).  Howarth's assumption that companies always vent natural gas during flowback is simply wrong.  Moreover, the U.S. Environmental Protection Agency is scheduled to finalize regulations to prohibit such venting altogether by April 3, 2012, just a few months from now.   

In addition, Howarth overestimated the amount of natural gas that comes to the surface during flowback.  He assumed that natural gas flows to the surface during flowback at the same rate at which it flows when the natural gas well is first put into production, after flowback is complete.  But during flowback, the well contains significant water, and that water holds the flow rate of natural gas below the rate at which gas will flow after flowback water is removed from the well.        

Cathles and his colleagues explained that Howarth also overestimated the amount of natural gas that leaks during storage, transmission, and distribution of the gas to market.   The EPA estimates that losses during those steps amount to 0.73% of the gas produced, but Howarth assumes losses during those steps will be 2 to 5 times higher than that, between 1.4 and 3.6%.

Another flaw in Howarth's analysis is that he fails to account for the fact that power plants that use natural gas are more efficient at converting heat energy to electricity than coal fired plants.  Howarth compared natural gas and coal on an equivalent heat energy basis, but a greater portion of the heat of combustion will be converted to electricity when using natural gas than when using coal. 

Finally, Cathles and his colleagues described an additional problem with Howarth's analysis.  When comparing the life cycle GHG footprints of coal and shale gas, one must consider the GHG effects of both carbon dioxide and methane.  This is necessary because both shale gas and coal produce carbon dioxide when burned, and because fugitive emissions (leaks) from natural gas piping and equipment result in releases of methane. 

But the need to consider both carbon dioxide and methane complicates the analysis.  A molecule of methane has a stronger GHG effect than carbon dioxide, but when carbon dioxide is emitted to the atmosphere, it remains there for a long time.  In contrast, methane breaks down over time.  Thus, the relative sizes of the GHG footprints of carbon dioxide and methane depend upon the time horizon chosen. 

Climate change is a long term process, and Cathles stated that most researchers use a 100 year time horizon when comparing the relative GHG effects of methane and carbon dioxide.  But Howarth chose a 20 year time horizon.  The shorter time horizon does not adequately account for the breakdown of methane, and thus overestimates the GHG effect of that compound.  Because a portion of the GHG footprint of natural gas comes from methane, Howarth's inappropriate use of a 20 year time horizon caused him to overestimate the GHG footprint of a given quantity of shale gas.

Other studies have reached conclusions similar to those of Cathles, who states that the GHG footprint of shale gas is one-third to one-half that of coal.  A study performed by researchers at Carnegie Mellon, whose work was funded by the Sierra Club, concluded that life cycle GHG footprint for shale gas is 20 to 50% lower than that for coal.  A study done in collaboration between Worldwatch Institute and Deutsche Bank concluded that the GHG footprint for shale gas is 47% lower than for coal.  A study by IHS Global Energy Research Associates did not calculate relative GHG footprints, but it noted some of the same problems with the Howarth study as Cathles identified.    

The Cathles team consisted of Lawrence M. Cathles III, Larry Brown, Milton Taam, and Andrew Hunter.  Howarth's co-authors included R. Santoro and Anthony Ingraffea.  The authors of the Worldwatch article were Mark Fulton, Nils Mellquist, Saya Kitasei, and Joel Bluestein.  The IHS paper was written by Mary L. Barcella, Samantha Gross, and Surya Rajan.

British Columbia Website for Mandatory Disclosure of Hydraulic Fracturing Fluid Composition is Launched

The Oil & Gas Law Brief reported on September 12, 2011 that British Columbia would begin requiring oil and gas well operators to disclose the composition of the hydraulic fracturing fluid they use on a well-by-well basis, and that the province would develop a website by January 2012 for the posting of such information.  The British Columbia Oil & Gas Commission has now launched that website.

In addition to providing general information about the process of hydraulic fracturing, the website will allow visitors to search for information on individual wells.  British Columbia's mandatory disclosure requirement went into effect for fracturing operations that take January 1, 2012 or later.  Operators have 30 days after completion of a well to post information, so information has been posted yet, but well-specific disclosures should begin to appear on the website soon. 

The new website is similar to the FracFocus website operated in the U.S. by the Ground Water Protection Council and the Interstate Oil & Gas Compact Commission.  At the U.S. website, many operators voluntarily post information regarding hydraulic fraturing fluid.  Also, some states that have enacted mandatory disclosure regulations have provided for public disclosure by requiring operators to post information on FracFocus.  The new British Columbia website is also named FracFocus, and it has a similar look to the site operated in the U.S.

British Columbia is the first Canadian province to enact regulations requiring operators to disclose the composition of hydraulic fracturing fluid.  Several states in the U.S., including Wyoming, Arkansas, Louisiana, Texas, Colorado, Montana, and West Virginia have enacted mandatory disclosure regulations, as has been reported during the past year in the Oil & Gas Law Brief.

Frack Quakes? Can hydraulic fracturing really cause earthquakes?

An earthquake that measured 4.0 on the Richter scale occurred near Youngstown, Ohio on New Year's Eve.  In the weeks before, several smaller earthquakes had occurred.  Many journalists have erroneously reported that scientists and state officials believe that hydraulic fracturing might have caused the earthquake.  Actually, the scientists and officials believe that the earthquake might have been caused by the operation of an injection disposal well, not by hydraulic fracturing.  Injection disposal and hydraulic fracturing are two different processes.  The journalists might have been confused by the fact that the disposal wells at issue happened to be used for disposal of wastewater from hydraulic fracturing operations, but that was mere coincidence.  Injection disposal wells are used to dispose of a variety of fluids.  Further, oil and gas operators sometimes dispose of fracturing wastewater by means other than underground injection. 

Nevertheless, the question whether hydraulic fracturing can cause earthquakes is a legitimate question.  This post discusses two issues: (1) whether underground injection disposal can cause earthquakes; and (2) whether hydraulic fracturing can cause earthquakes.

Injection Wells

Underground injection wells are regulated under the Safe Drinking Water Act.  The Environmental Protection Agency reports that about 550 to 800,000 underground injection wells exist in the United States.  Some of these are used for underground storage of fluids, including natural gas and oil.  For example, the Strategic Petroleum Reserve is an example of a facility that stores oil underground.  But most underground injection wells are used for the underground disposal of waste fluids.  An injection disposal well might be used for years, and may receive hundreds of million gallons of waste fluids. 

For several decades, many geologists have believed that the operation of injection disposal wells can cause earthquakes in certain circumstances in areas that already are prone to earthquakes.  Scientists refer to man-made earthquakes as examples of "induced seismicity."  One of the best known examples arises from the United States Army's operation of an injection disposal well at the Rocky Mountain Arsenal in Colorado during the 1960s.  The Army disposed of approximately 165 million gallons of waste fluids in the well from 1962 through 1966 at a depth of approximately 12,000 feet.  The Army quit using the well in early 1966 because geologists believed that fluid injections at the site were the cause of a series of earthquakes.   

More recently, researchers and officials have suggested that earthquakes occurring near the Dallas-Fort Worth airport in 2009 and a large number of mostly small earthquakes (an earthquake "swarm") near Guy, Arkansas in late 2010 through early 2011 might have been caused by injection disposal wells.  In addition, geologists also studied the possibility that underground injection wells caused a series of earthquakes that occurred near Trinidad, Colorado in 2001, but they did not reach a definitive conclusion.  Their report stated that circumstances "do not rule out the possibility of the Trinidad earthquakes being induced, but neither do they make a strong case for the Trinidad shocks being induced."  

Geologists also believe that the injection of water for enhanced recovery operations can cause earthquakes, and their belief is supported by a study of earthquakes occurring near Rangely, Colorado in the 1970s.

Because the earthquakes that are suspected of being caused by human activity occur only where geological faults and the possibility of earthquakes already exist, scientists have difficulty definitively linking seismic activity to underground injections.  But many geologists believe that evidence strongly supports the theory that human activity can induce earthquakes.  The type of evidence geologists examine in evaluating whether earthquakes might have been caused by underground injections include the distance between an underground injection point and the epicenter of an earthquake, and the timing of earthquakes relative to injection activity.  Geologists have suggested that society's use of underground injection disposal wells need not stop, and that risk can be minimized by halting or decreasing the rate of injections when particular injection wells are believed to have caused small earthquakes.

Hydraulic Fracturing

Geologists are less confident about a link between hydraulic fracturing and earthquakes than they are about a link between injection disposal wells and earthquakes.  Part of the reason for this is that a much smaller amount of fluid typically is injected during hydraulic fracturing than is injected in underground disposal operations.  Also, a hydraulic fracturing operation lasts for days, while an underground disposal well might operate for years.  Nevertheless, some geologists believe that fracturing can cause earthquakes, though generally only very small quakes.

The Oklahoma Geological Survey recently produced a report that found a possible correlation between fracturing activity and a series of earthquakes in that state, but the correlation was not definitive.  The report concluded that "uncertainties in the data make it impossible to say with a high degree of certainty whether or not these earthquakes were triggered by natural means or by the nearby hydraulic-fracturing operation."  As noted by the U.S. Geological Survey, "[e]arthquakes are not unusual in Oklahoma."  Thus, the earthquakes may have had a natural origin.

Another case study comes from Britain, where Caudrilla Resources was using hydraulic fracturing to produce natural gas from a shale formation in Lancashire.  An earthquake that measured 2.3 on the Richter scale, occurred on April 1, 2011.  Another quake, which measured 1.5 on the Richter scale, occurred on May 27, 2011.  A group of experts from across Europe studied the two earthquakes.  They concluded that it was "highly probable" that fracturing had caused the earthquakes, but that an "unusual combination of factors" that they said was unlikely to occur again had been necessary in order for fracturing to cause the earthquakes.  They estimated that, in the unlikely event that the factors did recur, the "worst-case scenario" was an earthquake with a maximum strength of 3.0 on the Richter scale.

Concluding Thoughts and References for Additional Reading

Geologists generally accept the idea that human activity, including the operation of injection disposal wells, can cause earthquakes in certain circumstances in areas that already have geological faults and the possibility of earthquakes.  Geologists have suggested that our society need not stop using injection disposal wells, and that any danger can be minimized by halting or slowing underground injections when small earthquakes begin to occur. It is not as widely accepted that hydraulic fracturing can cause earthquakes, but some geologists believe that hydraulic fracturing can cause small earthquakes in some circumstances.

For further reading, see Earthquake Hazard Associated with Deep Well Injection — A Report to the U.S. Environmental Protection Agency (1990, 74 pages), We Don't Have Earthquakes in Colorado, Do We? (April 2002 newsletter of the Colorado Geological Survey's Division of Minerals and Geology), a page on the U.S. Geological Survey website that asks "Can We Cause Earthquakes?," the Executive Summary of the report on the earthquakes in Lancashire (the full report, plus multiple appendices are available at the news page of the Caudrilla Resources website), a news story entitled SMU-UT Study Finds 'Plausible' Connection Between DFW Quakes and Saltwater Injection Well, and an order of the Arkansas Oil & Gas Commission placing a moratorium on injection disposal wells in a particular area after finding "[b]ased upon the studies of the Arkansas Geological Survey" that there is"no evidence" that hydraulic fracturing caused a series of earthquakes in Arkansas, but that there is "circumstantial evidence" that injection disposal wells might have been causing seismic activity.

Funding Sources for Hydraulic Fracturing Studies

January 2, 2012 post in the Oil & Gas Law Brief discussed two studies relating to whether natural gas is more likely to be found in water wells located near oil and gas activity, including Marcellus Shale wells that have been hydraulically fractured.  Multiple readers have asked about the source of funding for the study reported in the Oil & Gas Journal, and one reader asked about funding of the Duke study.  I understand that the study discussed in the Oil & Gas Journal was supported by Cabot Oil & Gas.  The Duke study was supported by Fred and Alice Stanback, who are financial donors to various environmental causes and organizations, and by the Duke Center on Global Change, an interdisciplinary center at Duke that focuses on climate change and other environmental issues.

Large Study Finds No Link Between Methane in Pennsylvania Water Wells and Hydraulic Fracturing

A group of scientists recently issued a report in which they conclude that methane is commonly found in water wells in northern Pennsylvania, but that the presence of methane is unrelated to hydraulic fracturing of the Marcellus Shale.  The scientists based their conclusions on the analysis of samples collected from more than 1700 water wells in Susquehanna County, Pennsylvania prior to proposed natural gas drilling. 

In the report published in December in Oil & Gas Journal, the scientists stated that methane is "nearly ubiquitous in water wells in this region, with over 78% of the water wells exhibiting detectable methane concentrations."  The scientists found no correlation between the presence of methane and the existence of nearby oil and gas activity, but they found a "clear correlation" with natural topography.  "Specifically, water wells located in lowland valley areas exhibit significantly higher dissolved methane levels than water wells in upland areas, with no relation to proximity of existing gas wells."

The scientists stated that each of their three findings ─ that methane in water wells is common in the area, that it is unrelated to hydraulic fracturing, but that it is related to topography ─ is supported by additional evidence.  For example,

Technical literature and historical publications confirm the presence of methane gas in natural seeps and water wells in this region for many decades, long before shale gas drilling operations were initiated in 2006." 

In fact, in 2004, the Pennsylvania Department of Environmental Protection published a "Fact Sheet" on methane in water wells.  Further, the scientists noted that, in an earlier 2011 study, the Center for Rural Pennsylvania sampled 48 water wells located at varying distances from natural gas wells in Pennsylvania, finding "no significant relationship of methane concentrations to distance from a gas well."

As for their conclusion that there is a relation between topography and methane concentrations, the scientists noted that similar results were obtained in a study conducted in West Virginia by the U.S. Geological Survey from 1997 to 2005.  In that study, the USGS sampled 170 water wells, finding that methane concentrations exceeding 10,000 ppb "only in wells located in valleys and hillsides, rather than hilltops."  Moreover, the conclusion is also supported by anecdotal testimony of water well drillers in Susquehanna County, who report that methane is frequently found in water wells in the County, but that "water wells with gas shows are most commonly observed in the valleys."   

In their recent report, the scientists also addressed a study published by a group from Duke University earlier in 2011.  Like the scientists who published the recent report in Oil & Gas Journal, the Duke researchers found that it is common for water wells to contain methane, without regard to whether the water wells are located near oil and gas activity.  But the Duke researchers, who based their study on a much smaller data set, concluded that higher levels of methane can be linked the existence of nearby oil and gas activity. 

The Duke group based their conclusions in part on using isotopic analyses of their water samples to distinguish between biogenic methane and thermogenic methane.  Biogenic methane is formed at relatively shallow depths beneath the earth's surface through biological processes associated with the decay of organic matter.  Thermogenic methane is created through non-biological processes, typically much deeper underground, when organic material is subjected to significant  heat and pressure.  Because the natural gas for which oil and gas companies are drilling is the thermogenic methane that is found in deeper formations, the existence of biogenic methane in a water well would not likely be caused by oil and gas activity.  

The Duke researchers concluded that, whenever they found biogenic methane in a water well, the presence of methane was not caused by oil and gas activity.  But when they found thermogenic methane in a water well, they concluded that oil and gas activity likely had caused the methane to be present.

The group of scientists that published their findings in Oil & Gas Journal noted, however, that some relatively shallow sandstones contain thermogenic methane, and that many water wells are drilled deep enough to intercept those sandstones.  Thus, the presence of thermogenic methane in a water well does not necessarily indicate the methane's presence is the result of by oil and gas activity. 

Further, the scientists explained that thermogenic methane from different formations sometimes can be distinguished by isotopic analyses, in the same way that thermogenic and biogenic methane can be distinguished.  Indeed, thermogenic methane from the Marcellus Shale has a different isotopic signature than the thermogenic methane from the shallower sandstones found in northern Pennsylvania, and the isotopic signature of the thermogenic methane found in some of the Duke study's samples is more consistent with methane that comes from the shallower sandstones, rather than from the Marcellus Shale.  Accordingly, the scientists state that the Duke study's results do not support a conclusion that Marcellus Shale drilling or hydraulic fracturing caused the presence of methane in the water wells sampled for the Duke study.

 

Postscript: Multiple readers have asked about the source of funding for the study reported in the Oil & Gas Journal, and one reader asked about funding of the Duke study.  I understand that the study discussed in the Oil & Gas Journal was supported by Cabot Oil & Gas.  The Duke study was supported by Fred and Alice Stanback, who are financial donors to various environmental causes and organizations, and by the Duke Center on Global Change, an interdisciplinary center at Duke that focuses on climate change and other environmental issues.

Interview with Keith Hall Regarding EPA Report on Pavillion, Wyoming

Yesterday, I was interviewed regarding the EPA's report relating to alleged groundwater contamination near Pavillion, Wyoming.  The approximately 5 minute interview touched on

  • how the EPA got involved 
  • what the EPA concluded (that oil and gas activity, perhaps including hydraulic fracturing, has contributed to groundwater contamination)
  • the problems with the study that have been cited by industry (including Encana, which operates natural gas wells in the area), and
  • the significance of the study.

Click here to see the interview.

West Virginia Governor Earl Ray Tomblin Signs Horizontal Well Act

The Office of West Virginia Governor Earl Ray Tomblin issued a press release on December 22 announcing that Tomblin has signed the Horizontal Well Act.  That legislation, which passed by wide margins in the West Virginia legislature, was discussed in the Oil & Gas Law Brief on December 19, 2011.

Encana's Response to EPA's Draft Report on Pavillion

On December 8, 2011, the EPA issued a draft report which concluded that oil and gas activity likely caused contamination of water wells near Pavillion, Wyoming (see Oil & Gas Law Brief, December 12, 2011).  Encana, which operates numerous natural gas wells in that area, criticized the EPA's draft report, stating that the EPA's data do not support its conclusions.  Since then, Encana has issued a statement that explains some of the reasons that it disputes the EPA's conclusions.

Encana explains that the EPA did not find any impact from oil and gas activity when it tested samples from the area's domestic water wells, which typically are drilled to depths of less than 300 feet.  "The EPA's reported results of all four phases of its domestic water well tests do not exceed federal or state drinking water quality standards for any constituent relating to oil and gas development." 

The EPA also collected samples from two much deeper monitoring wells (to depths between 783 and 981 feet) that the Agency drilled into a shallow natural gas reservoir.  Encana states that the water samples EPA collected from those monitoring wells contained "components of natural gas,"  but that is "an entirely expected result" given that natural gas is found naturally at the depths to which the monitoring wells were drilled.  Indeed, reports Encana, natural gas is found in commercial quantities at depths as shallow as 1100 feet, only slightly deeper than the EPA's monitoring wells, and no cap rock exists in the area to prevent some of that natural gas from migrating naturally to shallower depths.

Pavillion is a shallow natural gas field.  Naturally occurring methane (natural gas) exists throughout the subsurface geology, filling channel sands from millions of years ago.  This natural gas is commonly known to have been present in groundwater from domestic water wells for decades, dating back to well before any natural gas drilling started."

Encana's statement declared that, "Natural gas developers didn't put the natural gas at the bottom of the EPA's deep monitoring wells, nature did."

Encana also states that the EPA's lab analyses contain "unacceptable inconsistency."  Further, Encana states that additional problems are demonstrated by the analyses of the EPA's quality control (blank) samples.  Such blank samples do not contain water collected from domestic wells or monitoring wells, and instead contain ultra pure water that is put into supposedly clean sample collection containers.  The blanks are analyzed as a test to verify that the Agency is not inadvertently causing contamination by the use of unclean collection containers or improper sampling technique.  When analyzed, the blank samples should not contain contaminants.  But Encana states that man-made chemicals were found in many of the EPA's blanks, indicating a problem in the EPA's methodology.

Encana also expressed disappointment that the EPA published its draft report "before subjecting it to qualified, third-party, scientific verification."

Encana stated that the Pavillion area also had other water quality problems that existed before any natural gas drilling began in the area.

As far back as the 1880s, U.S. Geological Survey (USGS) reported about poor water quality in Pavillion.  More recent USGS reports dating back to 1959 have documented Pavillion water as unsatisfactory for domestic use due to high concentrations of naturally occurring sulfate, total dissolved solids and pH levels which commonly exceeded state and federal drinking water standards."

Other sources of information on Pavillion include the EPA's Region 8.  It has a webpage with information regarding the Agency's Pavillion investigation and links to various resources.  Also, the Wyoming Oil and Gas Conservation Commission has a "Pavillion Working Group" page with links to several documents.  In addition, the Petroleum Association of Wyoming has issued a statement about the EPA's draft report regarding Pavillion.

West Virginia Legislature Passes Bill to Regulate Shale Gas Development and Hydraulic Fracturing

Last week, the West Virginia legislature passed a bill to regulate hydraulic fracturing and shale gas development.  The Governor supported the legislation, called the Natural Gas Horizontal Wells Control Act. 

The Act applies to any horizontal well, other than a coalbed methane well, if it "disturbs three acres or more of surface," excluding pipelines and roads, or if more than 210,000 gallons of water are used at the well in any thirty day period.  The Act requires oil and gas operators to

  • obtain a drilling permit before commencing drilling or even beginning site preparation work   
  • publish a legal advertisement in the county where a well will be located prior to applying for a permit 
  • give notice to surface owners, as well as coal seam owners, operators, and lessees of the oil and gas operator's application for a drilling permit    
  • give advance notice before entering the property to conduct seismic operations  
  • give advance notice before entering the property to drill       
  • develop an erosion and sediment control plan for each well site   
  • develop a water management plan    
  • declare in the permit application what additives the operator anticipates using in any hydraulic fracturing fluid     
  • disclose, as part of a mandatory completion report, the additives actually used in the fracturing fluid   
  • keep records of the amount of flowback water recovered from the hydraulic fracturing   
  • keep records of the amount of produced water   
  • reclaim the well site after operations are complete by doing such things as sodding or planting seeds at the well site, and removing drilling equipment and supplies   
  • fill pits, except in certain specified circumstances   
  • dispose of cuttings in an approved manner  
  • locate wells at least 250 feet from any existing water well, 650 feet from any occupied dwelling (and any building above a specified size that houses animals), 100 feet from any lake or perennial stream, 300 feet from any naturally reproducing trout stream, and 1000 feet from of any intake of a public water supply
  • pay for surface damages   
  • post either a $50,000 bond for each well or a blanket bond of $250,000, payable to the state, to guarantee performance of the operator's duties.

The Act gives the surface owner and coal interests for the location where a well will be drilled the right to give written comments regarding a drilling permit application to the Department of Environmental Protection, and requires DEP to consider those comments before granting a permit.

The Act also  addresses civil litigation in which a surface owner alleges that his water well has been contaminated by oil and gas operations.  The Act establishes a rebuttable presumption that an oil and gas operator's activities have caused any contamination of a water well located within 1500 feet of the operator's well pad if the contamination occurs within six months of the completion of the gas well.  The oil and gas well operator may rebut the presumption by proving  by a preponderance of the evidence that the water was contaminated before the gas well was drilled, that the water well owner refused to allow the operator access to his property to test the water prior to drilling the gas well, or that something other than the oil and gas activity caused the contamination.  

In cases in which the West Virginia DEP determines that oil and gas activity has caused contamination, the Act also requires the operator to provide a replacement water supply, even if the operator disputes the DEP's determination, until the DEP or a court orders otherwise.  This requirement is in addition to any other relief that may be ordered by a court. 

The Act establishes fines and, in certain circumtances, the possibility of imprisonment for violations of the Act.

In addition, the Act addresses enforcement.  It provides for certain minimum qualifications for the Department of Environmental Protection's well supervisors and well inspectors.  For example, to qualify for those positions, an applicant must have at least two years of relevant oil and gas industry experience (or at least one year of experience if the applicant satisfies certain educational requirements), and must pass a written and oral examination.  The Act also requires that oil and gas supervisors be paid at least $40,000 per year and that inspectors be paid at least $35,000 per year.  To help fund DEP's enforcement activities, the Act increases permit fees to $10,000 for the first well drilled from a single pad, and to $5000 for subsequent wells drilled from the same pad.

The bill is lengthy, but can be found at the website of the West Virginia legislature (click on "Enrolled Version - Final Version" for HB 401 of the 2011 4th Special Session).

Texas and Colorado Adopt Rules Requiring Well Operators to Disclose the Compositon of Fluids Used in Hydraulic Fracturing

Today, both Texas and Colorado adopted regulations requiring the operators of oil and gas wells to disclose the composition of the fluids used in hydraulic fracturing.

In Texas, where oil and gas activity is regulated by the Railroad Commission, new rules require the operator of each hydraulically fractured well to disclose

  • the date of hydraulic fracturing
  • the county in which the well is located, as well as the longitude and latitude of the well
  • the total vertical depth of the well
  • the total volume of water used in hydraulic fracturing (or the type and volume of the base fluid if the base fluid is not water)
  • each additive used in the hydraulic fracturing fluid, as well as the trade name of the chemical, and the supplier
  • the intended function of the chemical (for example, whether it is intended as a biocide, corrosion inhibitor, etc.), and
  • the concentration of each chemical.

The operator is required to supply this information for posting at FracFocus, a website operated by the Ground Water Protection Council and the Interstate Oil & Gas Compact Commission.  The website has become a central location for the posting on information regarding the hydraulic fracturing of wells in several states.  Visitors to the website can search for wells by county, longitude and latitude, or the name of the operator, as well as by other criteria. 

An operator need not disclose the identity of a chemical if the supplier of the chemical contends that the chemical qualifies for trade secret under Texas Natural Resources Code, Section 91.851.  The standard for qualifying as a trade secret under that statute is based on the Restatement of Torts, Section 757, Comment B, as adopted by the Texas Supreme Court in Hyde Corp. v. Huffines, 314 S.W.2d 763, 776 (Tex. 1958). 

Factors that are considered under the standard adopted in that case include: (1) the extent to which information alleged to be a trade secret is known outside the company; (2) the extent to which the information is known by employees and others involved in the company's business; (3) the extent of the measures the company has taken to protect the secrecy of the information; (4) the value of the information to the company and its competitors; (5) the amount of effort or money expended by the company to develop the information; and (6) the ease or difficulty with which a person could properly acquire and develop the same information.

The regulations provide a procedure for various persons to challenge a claim of trade secret status.  The persons who have a right to challenge a trade secret claim are: (1) the landowner on whose land the well-head is located; (2) the landowner of adjacent property; and (3) a state agency with jurisdiction over a matter to which a claimed trade secret is relevant.  The regulations also require disclosure to health care providers in certain circumstances.

The new Texas rules will apply to all wells for which an initial drilling permit is issued on or after February 1, 2012.

The Colorado Oil and Gas Conservation Commission adopted regulations similar in substance to those adopted in Texas.  Colorado's new regulations will require operators of each oil or gas well that is hydraulically fractured in Colorado on or after April 1, 2012 to disclose to the public the operator's name, the date the well was fractured, and

  • the location of the well, including the county in which it was drilled and also the latitude and longitude of the wellhead 
  • the well's name and registration number 
  • the true vertical depth of the well 
  • the total volume of water or other base fluid used as the fracturing fluid (and, if the base fluid is not water, the identity of the base fluid)   
  • the trade name of each fracturing water additive, as well as the supplier and the intended function of the additive (e.g., biocide, corrosion inhibitor, friction reducer, etc.) 
  • the Chemical Abstracts Service (CAS) number for each additive (CAS numbers are unique identifiers that scientists use to identiy and distinguish each known chemical compound),  and
  • the maximum concentration of each additive.

The operator must disclose the information by posting it to FracFocus.  If a particular additive in the fracturing fluid is a trade secret, the operator does not have to identify it to FracFocus, but the operator must identify the chemical family of the additive.  In addition, the operator is required: (1) to identify the additive to a health professional who needs the information for purposes of treating or diagnosing a person who has been exposed to the fracturing fluid; and (2) to identify the additive to the Oil & Gas Conservation Commission if it needs the information for purposes of responding to a spill or release.

The Colorado rules provide a mechanism for a person to challenge a trade secret claim if he is "adversely affected" by the claim.

The Oil & Gas Law Brief previously reported on the Texas legislature enacting legislation to require the Railroad Commission to adopt disclosure regulations, the Railroad Commission's publication of proposed rules, and the Colorado Oil & Gas Conservation Commission's publication of proposed disclosure rules.

Significance of Test Results from Pavillion, Wyoming are Disputed

Residents of the area around Pavilion, Wyoming have complained about the quality of water from local wells, and some of them believe that hydraulic fracturing or other oil and gas activity may be to blame.  Late last week, the EPA released its draft report regarding its investigation of alleged ground water contamination near Pavillion, but the significance of the EPA's test results are disputed.  In a press release, the EPA stated: "EPA constructed two deep monitoring wells to sample water in the aquifer.  The draft report indicates that ground water in the aquifer contains compounds likely associated with gas production practice, including hydraulic fracturing."

The operator of the natural gas wells that the EPA believes caused the problem is Encana.  Encana issued a statement which noted that the EPA has tested water from monitoring wells that the EPA itself drilled just for the purpose of testing, and also water from domestic wells that local residents actually use to obtain water.  As for the monitoring wells, Encana stated that the EPA "drilled two deep monitoring wells into a natural gas reservoir," and it is "entirely expected" to find "components of natural gas" in such a reservoir.  Encana stated that the EPA's testing of domestic water wells "found no indication of impacts from oil and gas activity."  In addition, Encana stated:

The Pavillion area natural groundwater has a long history of poor quality.  Recent drinking water sample results are consistent with studies published by the U.S. Geological Survey and others over the past 50 years, prior to natural gas development in the area.

The Petroleum Association of Wyoming issued a statement that called the EPA's draft report "reckless" and "irresponsible."  The Association stated: "After several rounds of testing of private water wells, only one organic compound was found to exceed State or Federal Drinking Water standards.  This compound is an additive in plastics and one of the most commonly detected organic compounds in water." 

The EPA's report states that "[a]lternative explanations were carefully considered," but that the Agency believes oil and gas activity is the likely cause of the contamination the Agency claims to have found. 

Aside from the challenges that have been asserted to the EPA's conclusions, the Pavillion findings might have limited relevance to most circumstances in which companies perform hydraulic fracturing.  The EPA's own press release stated that the Agency's "draft findings are specific to Pavillion, where the fracturing is taking place in and below the drinking water aquifer and in close proximity to drinking water wells — production conditions different from those in many other areas of the country."  Indeed, in most shale plays, the formation being fractured is  more than a mile below drinking water aquifers, and often is separated by layers of impermeable rock.

Tuscaloosa Marine Shale News

Indigo Minerals issued a press release today stating that its first horizontal well targeting the Tuscaloosa Marine Shale has "resulted in a new oil discovery in Central Louisiana."  The press release stated that the well recently flowed at a rate of 534 barrels of oil equivalent per day, with 80% of that production actually being oil, with the remainder being natural gas and natural gas liquids.  Indigo stated that the oil is a light, sweet crude. 

Indigo drilled the well, called the Bentley Lumber 34H #1, in northwest Rapides Parish, to the Tuscaloosa Marine Shale formation, which sometimes is called the "Louisiana Eagle Ford."  Indigo used a 15-stage fracture stimulation.

Indigo has assembled nearly 260,000 net mineral acres within the Tuscaloosa Marine Shale.  Indigo stated in its press release that it has identified several additional locations to drill horizontal wells in 2012.  But Indigo stated that it will attempt to find a joint venture partner before beginning its 2012 drilling program.

Devon completed its Beech Grove Land Company 68H No. 1 Well in East Feliciana Parish in late October 2011.  Devon's initial report to the Louisiana Office of Conservation, which recently became available, indicates that the well tested at 120 barrels of oil per day of production.

And, Amelia Resources states in its weekly scout report for December 7 that Encana's Board of Education #1H Well in Amite County, Mississippi is producing an average of 119 barrels of oil per day, plus 49 mscf per day of gas. 

Several other wells are in the process of being drilled, completed, or tested.  Thus, much more news should be available soon.

New York DEC Extends Comment Period on Proposed Hydraulic Fracturing Regulations

The New York Department of Environmental Conservation announced last week that more than 6000 people attended the various public meetings that the DEC held regarding the Department's proposed hydraulic fracturing regulations, and that the DEC is extending the public comment period by 30 days, to January 11, 2012.

The proposed regulations would apply to "high-volume hydraulic fracturing," which would be defined as hydraulic fracturing operations that use more than 300,000 gallons of water.  The proposed regulations would:

  • prohibit high-volume hydraulic fracturing (HVHF) well pads within 4000 of an unfiltered surface water supply watershed, 2000 feet of any public water supply, and 500 feet of a primary aquifer
  • prohibit HVHF well pads within any 100-year floodplain
  • require that HVHF operations be conducted at depths at least 2000 feet below the surface and at least 1000 feet below the base of fresh groundwater
  • require operators to have a Spill Prevention Control and Countermeasure Plan
  • require operators to identify all fracturing water additives and the concentration of those additives in the fracturing water
  • regulate disposal of flowback, whether the disposal is by underground injection or by sending the flowback to a publicly owned treatment facility for treatment and discharge to a body of surface water
  • require operators to sample and test all residential water wells located within 1000 feet (if the water well owner will give permission) of a planned oil or gas well prior to beginning drilling, and to provide results to the water well owner, and
  • generally require high-volume hydraulic fracturing (HVHF) operators to contain all drilling fluids and cuttings within a closed system of piping and equipment, rather than in open pits.

The Oil & Gas Law Brief previously discussed the DEC's proposed regulations on October 3, 2011.  In other prior posts, the Oil & Gas Law Brief discussed on September 7 the DEC's release of its draft Generic Environmental Impact Statement relating to fracturing, as well as the DEC's recommendation to lift the state's moratorium on high volume hydraulic fracturing, and discussed on July 9 the DEC's release of an Economic Assessment Report relating to hydraulic fracturing. 

Brown Dense Generates Interest in Louisiana State Lease Sales

At Louisiana's state lease sale on October 12, 2011, the Department of Natural Resources accepted bids to lease more than 6000 acres of state‑owned land in East Carroll Parish, an area which historically has seen relatively little oil and gas activity.  The bidding on tracts in East Carroll appears to have been prompted by interest in the "Brown Dense," a shale formation that stretches across South Arkansas and North Louisiana, and which is expected to be an oil play.  The Brown Dense is sometimes called the "Lower Smackover" because it is located below the "Smackover," a formation from which companies have produced oil and gas for several decades in Louisiana. 

The winning bids for each of the tracts in East Carroll provided for a bonus of approximately $304 per acre, delay rentals of about $150 per acre, a 20% royalty, and a three‑year primary term.  In addition to the tracts for which bids were accepted at the October lease sale, private interests have nominated tracts of state‑owned water bottoms totaling more than 3000 acres in East Carroll for bid at the upcoming December 14, 2011 state lease sale.

Activity in the Brown Dense is at an early stage.  Southwestern Energy has received a permit for a Brown Dense well in Claiborne Parish, and is expected to begin drilling the well this year.  Southwestern already has begun drilling a Brown Dense well in Columbia County, Arkansas, and has plans to drill as many as ten Brown Dense wells in 2012.  XTO, a subsidiary of ExxonMobil, also has obtained a permit for a well in Claiborne Parish.  In addition, Devon Energy has obtained a permit for a well in Morehouse Parish.

The Oil and Gas Law Brief previously discussed the Brown Dense in posts dated August 31 and September 11, 2011.  The Department of Natural Resources has a page on its website with information regarding state lease sales, which are conducted by DNR's State Mineral and Energy Board.

EPA to Use Toxic Substances Control Act to Require Disclosures Regarding Hydraulic Fracturing Fluids

In response to a petition filed by Earthjustice and several other organizations, the United States Environmental Protection Agency has stated that it will use the Toxic Substances Control Act (TSCA) to draft regulations requiring companies to disclose information regarding "chemical substances and mixtures used in hydraulic fracturing."  Although the EPA has not indicated what information will be subject to disclosure, the agency stated that it will attempt to avoid duplication of "the well-by-well disclosure programs already being implemented in several states," and that it anticipates that its regulations will "focus on providing aggregate pictures of the chemical substances and mixtures used in hydraulic fracturing." 

In a November 23, 2011 letter to Earthjustice, the EPA stated that "the first step" in its development of disclosure regulations will be to "convene a stakeholder process to develop an overall approach that would minimize reporting burdens and costs, take advantage of existing information, and avoid duplication of efforts."  The EPA said that it will facilitate a public comment process by publishing an advance notice of its proposed rulemaking, "identifying key issues for further discussion and analysis."  The EPA did not specify in its letter or its public announcement when it would convene the stakeholder process or publish notice of its proposed rulemaking.

The EPA's decision grants a portion of the relief requested in Earthjustice's petition, but denies other portions of the requested relief.  Earthjustice's petition, dated August 4, 2011, requested that the EPA use 15 U.S.C. § 2607 (section 8 of TSCA) to require chemical manufacturers to report a broad range of information on all substances used in the exploration and production of oil and gas.  The EPA stated, however, that its disclosure regulations will apply only to substances used in hydraulic fracturing, and that the agency was denying Earthjustice's request for regulations relating to other substances used in oil and gas activities.  

EPA previously had denied another request contained in Earthjustice's petition  ─ a request that the EPA use 15 U.S.C. § 2603 (section 4 of TSCA) to require manufacturers to conduct toxicity testing of all "chemical substances and mixtures used in oil and gas exploration or production."  The EPA announced that decision in a letter dated November 2, 2011.  The letter explained that the EPA was rejecting the request for mandatory toxicity testing because Earthjustice's petition had not included information sufficient to support certain factual findings that EPA must make before it is authorized to order toxicity testing.  The statutorily-required factfindings include determinations that there is insufficient existing data regarding the effects that exposure to a substance has on health and the environment, and also that testing is necessary in order to develop such data.

As for the disclosure regulations that EPA has agreed to draft, it is unclear exactly what information will need to be disclosed.  Earthjustice's petition asked that chemical manufacturers be required to supply EPA with "various records," including the chemical and trade names of all substances manufactured for use in hydraulic fracturing, along with other information regarding each substance, including the amount produced; all existing data concerning the effects of exposure on health and the environment; copies of all health and environmental studies "known to" the manufacturers; and information regarding all adverse health or environmental effects that the manufacturers know have been "alleged to have been caused" by the substance.

Earthjustice, along with approximately  120 other organizations, submitted the August 4 petition pursuant to 15 U.S.C. § 2620 (section 21 of TSCA), which allows citizens to petition the EPA to draft TSCA regulations. 

Earthjustice is a San Francisco based organization whose website states that the organization was founded in 1971 as the Sierra Club Legal Defense Fund, but that the group later changed its name to reflect that it is independent of the Sierra Club, and that it provides legal representation to "hundreds" of clients in addition to the Sierra Club. 

Secretary of Energy Advisory Board Issues Second Report on Shale Gas Production

The Secretary of Energy Advisory Board on shale gas production issued its second "ninety day" report, dated November 18, 2011.  The group's first report, dated August 18, 2011, stated that shale gas production is important to the economy and our nation's energy security, but that several changes to regulations and procedures should be made to address environmental issues.  The first report made recommendations relating to reducing emissions, requiring disclosure of fracturing water composition, improving well construction standards, and prohibiting the use of diesel in fracturing fluid (see August 29, 2011 Oil & Gas Law Brief).  

The second report does not contain much in the way of new recommendations or conclusions.  Instead, it primarily discusses implementation of the recommendations contained in the first report.  For example, the second report expresses the Advisory Board's disappointment that there has not been more progress toward implementing the Board's prior recommendations, but the second report also acknowledges that progress has been made and that it has been a relatively short time since the release of the first report.  For each of the Advisory Board's prior recommendations, the second report also discusses which entity or entities would have to take action in order to implement the recommendation — the federal government, state governments, or some other organization.

In some reports, the Advisory Board is referenced as "SEAB."

Hydraulic Fracturing and Gasland: Separating Fact from Fiction

The movie Gasland portrays hydraulic fracturing as a cause of water well contamination, while industry supporters assert that there has never been a documented case of hydraulic fracturing causing contamination of groundwater.  So what are the facts?

 Gasland showed individuals lighting their faucets on fire, explained that the individuals' water wells were contaminated with methane (the principal component in natural gas), and suggested that hydraulic fracturing had caused the contamination.  The water wells probably did contain methane, but determining the cause of the contamination requires some investigation.  And to understand those investigations, it helps to understand a little about the ways methane can be formed.

 Methane is a flammable gas that is formed in one of two ways.  First, it can be produced by bacteria during the decomposition of organic matter.  This is the process that creates the methane found in landfills, swamps (called swamp gas), and in the intestines of cattle and other animals.  Methane produced in these biological processes is called "biogenic" methane.  When biogenic methane is formed underground, it generally is formed at fairly shallow levels ─ not more than a few hundred feet underground.  It has been well documented for years that a high proportion of water wells in some parts of the country contain significant amounts of biogenic methane.

 The second way methane can be formed is through the thermal decomposition of organic matter under high temperatures and pressures.  Methane created by this thermal process is called "thermogenic" methane.  Thermogenic methane is created when organic matter is buried deep underground by the accumulation of more and more sediment under the right circumstances.  Over thousands of years, the combination of high temperatures and pressures caused by the organic material being buried deep underground can lead to the formation of thermogenic methane.

Biogenic methane and thermogenic methane molecules are chemically the same, but scientists can tell the difference between the two types of methane by a couple of means of "chemical fingerprinting."  The first is isotopic analysis of the carbon atoms found in methane.  All carbon atoms have the same chemical properties, but a small fraction of carbon atoms have a different number of neutrons in the atomic nucleus than do most carbon atoms.  Because the fraction of carbon atoms that have the "odd" number of neutrons is different for thermogenic and biogenic methane, scientists can tell the difference between the two types of methane by using isotopic analysis. 

Also, the process that creates thermogenic methane also generally leads to small amounts of other hydrocarbons, such as ethane, propone, and butane.  The process that creates biogenic methane creates very little ethane, and no propane or butane.  Thus, scientists sometimes can "fingerprint" methane as being thermogenic or biogenic based on the presence or absence of other hydrocarbons.

 The methane recovered in natural gas drilling is thermogenic, not biogenic.  Thus, the presence of biogenic methane in a water well generally would not be caused by natural gas drilling, whereas the presence of thermogenic methane might be caused by drilling activity (though in some places, thermogenic natural gas naturally seeps to the earth's surface, so that the presence of thermogenic methane in a water well is not sufficient by itself to prove that oil and gas activity is the cause).

 Gasland discussed three water wells located in Colorado, and also discussed two additional places in Colorado where gas was seeping to the surface in the West Divide Creek area.  The Colorado Oil & Gas Conservation Commission, the arm of state government that regulates the oil and gas industry, investigated the contamination and has posted a report of its findings on its website.  Through testing, the Commission conclusively established that three of the five locations (two of the water wells and one of the seeps) contained biogenic methane that was unrelated to oil and gas activity.

Of the remaining two locations, the water well contained both biogenic and thermogenic methane, while the seep contained thermogenic methane.  That left the question of what caused thermogenic methane to contaminate the water well and the seep.  The Commission concluded that oil and gas activity was the cause, but that the contamination had not been caused by hydraulic fracturing.  Rather, the problem had been caused by improper well construction (the casing and cementing of the natural gas wells).

This result is consistent with statements previously made in the Oil & Gas Law Brief that standards for casing and cementing wells is an issue that should be discussed, but that hydraulic fracturing rarely, if ever, is a problem.  Further, the Colorado result is consistent with investigations of water well contamination in other places.  Those investigations repeatedly conclude either that oil and gas activity was not the cause of the contamination, or that oil and gas activity was the cause, but that the specific activity that led to the problem was a well construction problem, not hydraulic fracturing.  Lisa Jackson of the EPA and other officials in the Obama administration have stated that they are unaware of any documented cases of groundwater being contaminated by hydraulic fracturing.  Numerous other government agencies have reached similar conclusions. 

 And I recently attended a major conference where a representative of the Natural Resources Defense Council stated that he advocates several reforms relating to the oil and gas industry (including mandatory disclosure of hydraulic fracturing fluid composition, spill prevention, and more attention to well construction standards), but that he does not think the threat of groundwater contamination by the hydraulic fracturing process itself is an issue.

 In short, many knowledgeable people assert that all the energy that is being poured into the debate over hydraulic fracturing would be better spent on other safety issues.  

Early Results of Study Indicate No Direct Link Between Hydraulic Fracturing and Groundwater Contamination

An interdisciplinary team from the University of Texas has announced that early results from its study of hydraulic fracturing show no direct link between hydraulic fracturing and groundwater contamination.  The team stated that, in some instances, other aspects of oil and gas activity might have led to contamination, but that hydraulic fracturing itself does not appear to have been the cause.

The team's leader, Dr. Charles "Chip" Groat stated: 

From what we've seen so far, many of the problems appear to be related to other aspects of drilling operations, such as poor casing or cement jobs, rather than to hydraulic fracturing per se." 

The team's preliminary results also indicate that spills of wastewater, sometimes are an issue: 

Many allegations of groundwater contamination appear to be related to above‑ground spills or other mishandling of wastewater produced from shale gas drilling, rather than from hydraulic fracturing itself."

These preliminary conclusions that spills and poor casing and cementing sometimes can be a problems, but that hydraulic fracturing itself rarely is, are consistent with views previously stated in the Oil & Gas Law Brief.  On April 24, 2011 and April 25, 2011, the Oil & Gas Law Brief carried a two‑part series ─ "Hydraulic Fracturing:  What safety issues should we be discussing?" ─ in which the author stated that regulations relating to spills, casing, and cementing are generally sound, but are the issues we should be discussing, rather than hydraulic fracturing itself.

The University of Texas study was announced on May 9, 2011 (see Oil & Gas Law Brief, May 10, 2011).  The leader of the interdisciplinary study team is Chip Groat, head of the U.S. Geological Society under Presidents Clinton and George W. Bush.  Groat stated:  "Our goal is to inject science into what has become an emotional debate and provide policymakers a foundation to develop sound rules and regulations."  The group's final report is expected early next year.

Colorado Considers Rules for Mandatory Disclosure of Hydraulic Fracturing Water Composition

The Colorado Oil and Gas Conservation Commission has proposed regulations that would require public disclosure of the composition of hydraulic fracturing water.  In particular, the proposed regulations would require operators of each oil or gas well that is fractured in Colorado to disclose to the public the operator's name, the date the well was fractured, and

  • the location of the well, including the county in which it was drilled and also the latitude and longitude of the wellhead 
  • the well's name and registration number 
  • the true vertical depth of the well 
  • the total volume of water or other base fluid used as the fracturing fluid (and, if the base fluid is not water, the identity of the base fluid)   
  • the trade name of each fracturing water additive, as well as the supplier and the intended function of the additive (e.g., biocide, corrosion inhibitor, friction reducer, etc.) 
  • the Chemical Abstracts Service (CAS) number for each additive (CAS numbers are unique identifiers that scientists use to identiy and distinguish each known chemical compound),  and
  • the maximum concentration of each additive.

The operators would have to disclose the information by posting it to FracFocus, a website operated by the Ground Water Protection Council and the Interstate Oil & Gas Compact Commission that has become a central location for the posting on information regarding the hydraulic fracturing of wells in several states.  Visitors to the website can search for wells by county, longitude and latitude, or the name of the operator, as well as by other criteria. 

If a particular additive in the fracturing fluid is a trade secret, the operator would not have to identify it to FracFocus, but the operator would have to identify the chemical family of the additive.  In addition, the the operator would be required: (1) to identify the additive to a health professional who needs the information for purposes of treating or diagnosing a person who has been exposed to the fracturing fluid; and (2) to identify the additive to the Oil & Gas Conservation Commission if it needs the information for purposes of responding to a spill or release.

The Colorado Oil and Gas Commission website has information regarding the proposed regulations, including

The website also includes information on requesting the opportunity to speak at the public hearing, and on submitting written comments, which can be made on-line through November 23, 2011.

A Colorado Oil and Gas Conservation Commission official has stated that the proposed regulations, if approved, could go into effect as early as February 1, 2012.

If Colorado adopts mandatory disclosure rules, it will join several states, including Wyoming, Arkansas, Montana, Louisiana, and West Virginia that have already enacted similar regulations.  In addition, Texas is in the process of enacting such regulations, and New York is considering the idea.

In addition to being available at the Oil and Gas Conservation Commission's website, the proposed regulations appear in the November 10, 2011 edition of the Colorado Register.

Interview: Hydraulic Fracturing Safety and EPA's Hydraulic Fracturing Study Plan

On November 7, 2011, the Oil and Gas Law Brief discussed the EPA's release of the final draft of its hydraulic fracturing study plan, and two days later, LexBlog Network interviewed me regarding the plan.  Attached is a link to a video of that interview.

EPA Announces Release of Final Draft of Hydraulic Fracturing Study Plan

Late last week the United States Environmental Protection Agency announced the release of a final draft of its hydraulic fracturing study plan.  The study, which EPA is performing at the request of Congress, will focus on potential impacts of hydraulic fracturing on drinking water. 

The EPA will collect and analyze samples from seven locations, and perform modeling based on its analyses.  The seven locations include two sites where the EPA will conduct "prospective case studies."  At the "prospective" sites, the EPA will take samples and evaluate conditions through the entire life cycle of a well, starting before the wellpad is constructed and drilling begins, through the drilling and fracturing processes, and afterward, when the well is put into production.  Groundwater samples from the area around each site will be analyzed for several substances, and samples of the flowback water also will be analyzed. 

The locations of the two "prospective" sites are  

  • DeSoto Parish, Louisiana (Haynesville Shale)  
  • Washington, County, Pennsylvania (Marcellus Shale). 

The operator of the well in DeSoto Parish will be Chesapeake, and the operator at the well in Washington County will be Range Resources. 

The EPA also will conduct five "retrospective case studies" to analyze alleged impacts of hydraulic fracturing on groundwater at five sites where wells already have been drilled and hydraulically fractured.  The five "retrospective" sites are

  • Killdeer and Dunn Counties, North Dakota (Bakken Shale) 
  • Wise and Denton Counties, Texas (Barnett Shale)  
  • Bradford and Susquehanna Counties, Pennsylvania (Marcellus Shale)  
  • Washington County, Pennsylvania (Marcellus Shale)  
  • Los Animas County, Colorado (Raton Basis coalbed).

The seven locations have different characteristics, and include a shale formation from which oil is produced (the Bakken Shale location in North Dakota), a site where coalbed methane is produced (the Raton Basin site in Colorado), and five sites where natural gas is produced from shale (the Haynesville, Barnett, and Marcellus Shale locations).

The EPA plans to issue a first report by the end of 2012 and an additional report in 2014.  The EPA also plans to provide quarterly updates on the progress of its study.  The EPA first announced its intent to perform the study in March 2011.  In addition to outlining the EPA's plans for its study, the final draft released last week has background information on drilling and the hydraulic fracturing process.

EPA Announces Plans to Regulate Disposal of Hydraulic Fracturing Water

The United States Environmental Protection Agency recently announced plans to develop regulations for the disposal of flowback water recovered from the hydraulic fracturing of shale formations.  Specifically, the EPA announced plans to require that flowback water be pre-treated before it is sent to publicly-operated wastewater treatment plants.

What is flowback?

 "Flowback" water is a byproduct of "hydraulic fracturing," a process that facilitates the production of oil and natural gas by using hydraulic pressure to create fractures in low-permeability, underground rock formations.  Water, along with sand and a small amount of other additives, is used transmit the hydraulic pressure.  After the fracturing is complete, the operator of the oil or gas well that is being fractured allows the pressure of the underground formation to push the water back to the surface, where it is recovered.  The recovered water is called "flowback."

Why is the EPA planning to add regulations?

The EPA is responding to concerns that many treatment plants are not designed to remove some of the contaminants found in flowback, which can contain the substances originally added to the fracturing water to facilitate the fracturing process, as well as other substances that dissolve into the fracturing water from the formation being fractured.  The other substances that are naturally found underground and which can dissolve into the flowback include salts, metals, and naturally-occurring radioactive materials.  Further, the salts sometimes can interfere with the working of wastewater treatment plants, though this usually does not occur because the operators of treatment plants usually combine the flowback with larger streams of water from other sources, so that the concentration of salts is diluted to a concentration level that does not interfere with the operation of treatment plants.

What would the regulations do?

The regulations have not been developed yet, so no one knows exactly what the planned regulations will say.  The EPA's announcement suggests that the regulations will require that, prior to flowback being sent to a treatment plant, the water must be pre-treated to remove contaminants that would not be adequately removed by the treatment plant itself or would possibly interfere with the treatment plant's operations.

When will the regulations be complete?

The EPA expects to gather information and input from stakeholders, draft regulations, and then seek public comments in 2014.

Is flowback always sent to treatment plants?

No.  Environmental regulations prohibit anyone from discharging flowback directly into streams, lakes, or other surface waters, but that does not mean that all flowback is sent to treatment plants. Operators typically do one of three things with flowback.  First, they often dispose of the flowback in underground injection wells, under regulation by the Safe Drinking Water Act.  Second, operators sometimes recycle the flowback for use in future fracturing operations, but such recycling is not always feasible.  Third, operators sometimes send the flowback to wastewater treatment plants

How was the announcement made?

The EPA announced its plans in its Final 2010 Effluent Guidelines Program Plan.  Section 304 of the Clean Water Act requires EPA to publish such a plan every two years to identify sources that discharge water either directly to surface waters or to wastewater treatment plants, and which EPA has selected for new or additional regulations.  The EPA published its preliminary 2010 Plan on December 28, 2009 at 74 Fed. Reg. Notice 68599.

Did EPA announce anything else in its Final 2010 Plan?

Yes, EPA announced plans to develop regulations for other types of discharges, including water produced during coalbed methane extraction.

What information is available from EPA?

Information available on EPA's website includes:

 

Deadline Extended for EPA to Implement Air Rules for Hydraulic Fracturing and the Oil and Gas Industry

The July 28, 2011 post in the Oil and Gas Law Brief reported that, in settlement of litigation with an environmental organization, the EPA committed to enacting regulations by February 28, 2012 to govern air emissions from certain oil and gas facilities, as well as emissions that occur during the process of hydraulic fracturing.  The EPA announced earlier this week that the parties to the litigation have agreed to extend that deadline by 35 days, to April 3, 2012.  Earlier today, the EPA published a notice in the Federal Register stating that the deadline to submit public comments regarding the proposed rules has been extended to November 30, 2011.  The proposed air rules were published in the Federal Register on August 23, 2011.

Louisiana Adopts Rule Requiring Disclosure of Hydraulic Fracturing Fluid Composition

The Louisiana Department of Natural Resources announced today that it has adopted a regulation that requires operators to disclose the composition of fracturing fluid used in each well fractured in Louisiana.

The new regulations requires operators to disclose

  • the volume of hydraulic fracturing fluid used
  • the types of additives used (for example, biocides, corrosion inhibitors, friction reducers, etc.), as well as the volume of each type
  • the trade name and supplier of each additive, and 
  • a list of the chemical compounds contained in the additives, along with the maximum concentration of each compound.

If the identity of the chemical compound is a trade secret, the operator would be excused from identifying the compound, but would be required to identify the chemical family to which the compound belongs.

Louisiana's proposed regulation would require that the mandated disclosure be made either to the Office of Conservation or to FracFocus, a website operated by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission.  FracFocus posts information regarding fracturing fluid composition on a well-by-well basis, using information voluntarily submitted by operators. 

The text of the regulation can be found at page 3064 of the October 2011 Louisiana Register.  The regulation was adopted with the same language as was proposed in DNR's notice of intent.

The Oil & Gas Law Brief previously reported on DNR's proposal of the rule in a post dated July 11, 2011, and reported on public comments regarding the proposed regulation in a post dated  September 4, 2011.

Pennsylvania Governor to Implement Recommendations of Marcellus Shale Advisory Commission

Pennsylvania Governor Tom Corbett announced plans to implement numerous recommendations made by the Marcellus Shale Advisory Commission, "including changes to enhance environmental standards, an impact fee, and a plan to help move Pennsylvania toward energy independence."

The recommendations Corbett plans to implement include:

  • Increasing well setback distances for Marcellus wells from private water from 200 feet to 500 feet, and to 1000 feet from public water systems
  • Increasing setback distances from 100 feet to 300 feet from streams, rivers, ponds, and other bodies of water
  • Increasing bond requirements from $2000 to $10,000 for wells
  • Increasing blanket bonds (that a company can post in lieu of bonds for individual wells) from $25,000 to $250,000      
  • Expanding an unconventional gas operator's "presumed liability distance" for water well contamination from 1000 feet to 2500 feet      
  • Extending the duration of presumed liability from 6 months to 12 months after completion of a gas well        
  • Giving the Department of Environmental Protection the ability to take quicker action to revoke permits from any operator who consistently violates regulations        
  • Doubling the authorized penalties from $25,000 to $50,000 for civil violations of environmental regulations         
  • Doubling daily penalties from $1000 to $2000     
  • Subjecting wells to an impact fee of $40,000 in the first year, $30,000 in the second year, $20,000 in the third year, and $10,000 in the fourth year.

Under Governor Corbett's plan, 75 percent of the revenue from impact fees would be retained at the local level, with 25 percent going to the State.  Much of the State's share would be dedicated to roads.

Governor Corbett also announced plans to promote energy independence and reduce reliance on foreign oil by helping convert fleets of school buses and mass transit vehicles to the use of natural gas, and developing "Green Corridors" with refueling stations for natural gas vehicles at least every 50 miles.

Governor Corbett's announcement stated that most of the Marcellus Shale Advisory Commission's regulations can be implemented by directives he will grant to executive agencies, but that about a third of the recommendations will require legislative action.  Corbett stated that he would submit a proposal to the legislature in the near future.

North Carolina Studies Possible Shale Gas Production

The areas of the country with ongoing or contemplated shale gas production continue to increase in number.  The North Carolina Department of Environment and Natural Resources (DENR) has launched a study of possible shale gas production.  The study was prompted by a geological survey that shows the potential for shale gas production from the Triassic Strata of the Deep River Basin in the central part of the state.  The survey discusses a shale that stretches across approximately 25,000 acres at depths of less than 3000 feet in Lee and Chatham Counties. 

DENR's website contains information about its planned study, existing regulations, upcoming public meetings that will be held October 10 and 18, information about how the public can submit comments via mail or email, a PowerPoint presentation made by the North Carolina Geological Survey to the Environmental Review Commission, and a circular about natural gas and oil in North Carolina.   

New York DEC Releases Proposed Hydraulic Fracturing Regulations

On September 28, the New York Department of Environmental Conservation announced its release of proposed regulations for "high-volume hydraulic fracturing," which the proposed regulations define as hydraulic fracturing operations that use more than 300,000 gallons of water.  The proposed regulations would:

  • prohibit high-volume hydraulic fracturing (HVHF) well pads within 4000 of an unfiltered surface water supply watershed, 2000 feet of any public water supply, and 500 feet of a primary aquifer
  • prohibit HVHF well pads within any 100-year floodplain
  • require that HVHF operations be conducted at depths at least 2000 feet below the surface and at least 1000 feet below the base of fresh groundwater
  • require operators to have a Spill Prevention Control and Countermeasure Plan
  • require operators to identify all fracturing water additives and the concentration of those additives in the fracturing water
  • regulate disposal of flowback, whether the disposal is by underground injection or by sending the flowback to a publicly owned treatment facility for treatment and discharge to a body of surface water
  • require operators to sample and test all residential water wells located within 1000 feet (if the water well owner will give permission) of a planned oil or gas well prior to beginning drilling, and to provide results to the water well owner, and
  • generally require high-volume hydraulic fracturing (HVHF) operators to contain all drilling fluids and cuttings within a closed system of piping and equipment, rather than in open pits.

The DEC also announced a series of public meetings that will be held regarding the proposed regulations and the Supplemental Generic Environmental Impact Statement that DEC previously issued regarding high-volume hydraulic fracturing (see July 9 post in the Oil & Gas Law Brief).

Judgment Striking Down Morgantown Fracturing Ban is Now Final After City Inadvertently Misses Appeal Deadline

On August 17, 2011, the Oil & Gas Law Brief reported that a West Virginia judge had entered an order striking down a ban on hydraulic fracturing enacted by the City of Morgantown.  The judge ruled that West Virginia statutes make oil and gas regulation exclusively a matter of state law, and that local governments do not have authority to enact additional regulations.  That judgment is now final. 

The City of Morgantown apparently had planned to appeal, but media reports indicate that the City inadvertently missed the 30-day deadline to file a notice of appeal.  The 30-day deadline is found in West Virginia Rule of Civil Procedure 73, which was amended in December 2010 to add a subsection (c) that requires a party to file a notice of appeal within 30 days of the judgment being appealed.  Previously, parties "perfected" an appeal by taking certain steps within four months of a judgment.  One report quoted the City Manager as saying that he thought the City had four months to appeal, and quoted the City's lead counsel for the litigation as saying, "[W]e overlooked the recent amendment, and I take responsibility for that." 

Anschutz Files Suit Challenging Town of Dryden's Ban on Drilling

Plaintiffs have filed suit in two separate actions, asking New York courts to strike down local regulations that purport to prohibit oil and gas drilling.  In one action, Anschutz Exploration filed suit in Tompkins County, challenging the Town of Dryden's ban on drilling.  In the other action, Cooperstown Holstein Corporation filed suit in Ostego County, challenging a ban on drilling enacted by the Town of Middlefield.

In both cases, the plaintiffs argue that the local bans on drilling are barred by a state statute which indicates that Article 23 of New York's Environmental Conservation Law (ECL) is designed to be a comprehensive system of oil and gas regulation that is administered by a single agency, the Department of Environmental Conservation.  Specifically, the statute declares:

The provisions of this article shall supersede all local laws or ordinances relating to the regulation of the oil and gas and solution mining industries; but shall not supersede local government jurisdiction over local roads or the rights of local governments under the real property tax law."

This issues has been litigated before.  In Envirogas, Inc. v. Town of Kiantone, the parties disputed the validity of a town zoning ordinance that required a person to pay a $2500 compliance bond and a $25 permit fee in order to drill a well within the town.  The district court struck down the law, stating that the mere existence of state regulation does not prevent a local government from regulating on the same topic, "But where a state law expressly states that its purpose is to supersede all local ordinances then the local government is precluded from legislating on the same subject matter unless it has received 'clear and explicit authority' to the contrary."  The Town of Kiantone did not have any such "clear and explicit" authority.

Kiantone argued that its zoning ordinance was not preempted because the ordinance related to "local areas of concern not specifically addressed by the ECL."  The court rejected that argument, explaining that, because the ECL expressly states that it intended to "supersede all local laws or ordinances," it preempts not just local regulations that are inconsistent with the ECL, "but also any municipal law which purports to regulate gas and oil well drilling operations, unless the law relates to local roads or real property taxes." 

The Town of Kiantone also argued that its regulation related to local roads, but the court rejected that argument too.  The court explained the purpose of the ECL's provision that local laws regarding roads are not preempted.

Clearly the purpose of the 'local roads' exception was to allow local officials to continue to assert weight and speed restrictions upon vehicles operated on their highways, whether or not these vehicles were utilized in oil and gas production."

Further, the court noted that the challenged zoning provision applied only to the oil and gas industry, and not to other persons or industries who use and could damage local roads.  The appellate court unanimously upheld the trial court's ruling.  See Envirogas, Inc. v. Town of Kiantone, 447 N.Y.S.2d 221 (N.Y. Sup.), aff'd, 454 N.Y.S.2d 694 (N.Y. App. Div.), appeal denied, 444 N.E.2d 1013 (N.Y. 1982).

In its complaint, Anschutz states that the Town of Dryden amended its zoning ordinance in August 2011 to add a Section 2104 that prohibits oil and gas drilling and certain other oil and gas activities within Dryden .  Anschutz asserts that it would be adversely affected by that prohibition because the company has invested $5.1 million in acquiring lease rights within the area where drilling would be banned.

In its complaint, Cooperstown Holstein alleges that it owns land within the Town of Middlefield, as well as the rights to develop the minerals beneath that land.  Cooperstown Holstein alleges that, in June 2011, the Town  enacted a new zoning ordinance that prohibits "[h]eavy industry and all oil, gas or solution mining and drilling."  Cooperstown Holstein alleges that it has leased its land for oil and gas development, and that it will be adversely affected if its lessee cannot conduct oil and gas operations on the leased land.

It is impossible to know how the courts will rule, but based on the language of  ECL § 23-0303(2) and Envirogas, it appears that Anschutz and Cooperstown Holstein have strong arguments for invalidating the challenged zoning ordinances that purport to ban drilling.   

Pennsylvania Court's Ruling Will Create Confusion Regarding Right to Produce Gas from Marcellus Shale

A Pennsylvania appellate court recently issued a decision that will create uncertainty regarding who owns the right to produce natural gas from the Marcellus Shale in certain circumstances -- namely, whenever a chain of title contains a deed that grants the right to produce "minerals," without specifically referring to a right to produce natural gas. 

 In Pennsylvania, as in most states, the general rule is that the surface owner has the right to produce such substances as coal, oil, and natural gas from beneath his land, unless he or a prior owner of the surface has executed a deed that grants the right to produce one or more of those substances to someone else. 

In Butler v. Charles Powers Estate, 2011 WL 3906897 (Pa. Super.), one of the issues was whether a deed that granted the right to produce "minerals and Petroleum Oils" included a grant of the right to produce natural gas from the Marcellus Shale.  Many people who follow Pennsylvania oil and gas law would have concluded that the deed did not grant a right to produce natural gas, based on prior Pennsylvania Supreme Court decisions holding that:

  • the right to produce coal includes the right to produce natural gas contained within the coal, U.S. Steel Corp. v. Hoge, 468 A.2d 1380 (Pa. 1983)
  • but a grant of the right to produce "all minerals" generally does not include the right to produce oil, Dunham v. Kirkpatick, 101 Pa. 36 (1882)
  • the grant of a right to produce "minerals" does not include the right to produce oil or natural gas, Highland v. Commonwealth, 161 A.2d 390 (Pa.), cert. denied, 81 S. Ct. 234 (1960), and
  • the right to produce "oil" does not include the right to produce natural gas, Bundy v. Myers, 94 A.2d 724, 725 (Pa. 1953).  

And the lower court in Butler ruled as many people would have predicted, issuing a judgment based on the parties' pleadings (before evidence was taken) that the deed's grant of a right to produce "minerals and Petroleum Oils" did not include a grant of the right to produce natural gas from the Marcellus Shale.  But the appellate court reversed, remanding the case to the lower court to give the appellant the chance to prove whether the deed's grant included the right to produce natural gas from shale. 

The appellate court reasoned that the prior Pennsylvania Supreme decisions did not answer such questions as whether shale is a "mineral," whether natural gas found in shale "constitutes the type of conventional natural gas contemplated in Dunham and Highland," and whether there should be a rule for shale similar to the rule for coal that the person who owns the coal owns the right to produce natural gas from the coal.

At some level, there is logic to the appellate court's suggestion that perhaps shale is analogous to coal, and that perhaps the person who owns the right to produce the shale should have the right to produce the natural gas found inside the shale.  On the other hand, a strong argument can be made that too much is being made of the fact that natural gas is located inside the shale because natural gas is always found inside the pore spaces of either coal or underground rock formations.  And the Pennsylvania Supreme Court has held that the right to produce coal includes the right to produce natural gas found in coal, but that that right to produce "minerals" does not include the right to produce natural gas found in rock formations.  Shale is a type of rock formation. 

The Butler appellate court's reference to "conventional" gas suggests that the court may have been influenced by the fact that hydraulic fracturing is used both in producing gas from coal and in producing gas from shale.  Perhaps the court believed that there is an  important distinction between gas tightly bound inside relatively impermeable rock, so that it can only be produced by use of hydraulic fracturing, versus gas in a rock whose permeability allows the gas to flow relatively freely.  But it is questionable whether the use of a similar production process should override what otherwise seemed to be a settled matter of property law regarding who owns the right to produce natural gas found in formations other than coal beds.

But whatever the merits of shale being treated like other rock formations versus shale being treated like coal, Butler will have an unfortunate result -- it will create confusion about who owns the right to produce natural gas from shale if there is a deed that grants him the right to produce "minerals," but the deed does not expressly refer to a right to produce gas.  This question ultimately will have to be resolved by the Pennsylvania Supreme Court.  It is an important enough issue that the Supreme Court should grant immediate review of the issue. 

If the Pennsylvania Supreme Court does not grant immediate review, the Butler case will go back to the trial court for formal discovery, followed by a trial, followed by a new trip to the appellate court, and only after all of those steps would the case be ready for potential review by the Pennsylvania Supreme Court.  That process easily could take a couple of years, and perhaps longer.  It would be very unfortunate to allow doubts about title to fester for that long.  Such doubts would not only discourage drilling on property affected by deeds referring to the right to produce "minerals" and not referring to "gas" expressly, but such doubts also will create uncertainty about property values for property that may or may not include the right to produce shale gas, and create uncertainty about whether some oil and gas leases were granted by the appropriate lessors.  Such doubts could harm a large number of innocent persons.

Canadian Province to Require Disclosure of Hydraulic Fracturing Fluid Composition

British Columbia Premier Christy Clark announced that her province will begin requiring companies to public disclose the composition of fracturing fluid.  The information will be posted on a well-by-well basis on a website similar to FracFocus, a website where many companies are posting fracturing water composition for wells drilled in the United States.  The British Columbia website is expected to be operational in January 2012, but industry officials stated that they will begin voluntarily disclosing fracturing water composition before then.

It appears that the mandatory disclosure will provide some protection for trade secrets.  If so, the British Columbia mandatory disclosure rules will resemble those enacted by several states in the U.S. to require broad public disclosures, while providing protection for information that can meet trade secret status, a standard that the law has developed in other contexts to protect information that otherwise would have to be disclosed pursuant to some law, but which can be protected from disclosure under narrow circumstances.

Premier Clark made the announcement during an appearance at the annual BC Oil and Gas Conference in Fort Nelson.  She stated: "British Columbia is committed to the development of a more open and transparent natural gas sector and the disclosure of hydraulic fracturing practices and additives supports this goal.  Now, all British Columbians will have access to the information they need to make informed decisions about the industry's operations."

The B.C. government news service explained that hydraulic fracturing has never caused any water quality problems in the province, and that the mandatory disclosure requirement is merely a protective measure. 

British Columbia's online registry is part of a broader piece of work to ensure water is protected and conserved as shale gas development occurs.  It is important to note that there has never been an incident of harm to groundwater from hydraulic fracturing operations within British Columbia." 

The British Columbia government's website includes an article about Premier Clark's announcement, as well as an approximately two-minute video of the portion of a speech in which she made the announcement.

Premier Clark's announcement was made the same day that the Canadian Association of Petroleum Producers announced "Guiding Principles for Hydraulic Fracturing."  The guiding principles include a commitment to supporting the disclosure of fracturing fluid additives, the development of additives with the least environmental risks, and the development of best practices, as well as a commitment to "safeguard[ing] the quality and quantity of regional surface and groundwater resources." 

Brown Dense Begins to Attract Attention

The Brown Dense is a shale formation that stretches across North Louisiana and South Arkansas.  As reported in an August 31 post of the Oil and Gas Law Brief, the Brown Dense is a potential new oil play that is attracting substantial interest from the oil and gas industry.  Companies have acquired oil and gas leases covering hundreds of thousands of acres in the area where the Brown Dense is located, and are preparing to drill multiple wells this year and even more wells next year. 

The Brown Dense is now also starting to attract attention from the mainstream media.  Today's Times Picayune carried a story by Richard Thompson that focuses on the Brown Dense.  Thompson's story also discusses the Tuscaloosa Marine Shale, a potential new oil play that stretches across central Louisiana, and the Haynesville Shale, an existing natural gas play in northwestern Louisiana.  With oil prices remaining high and natural gas prices depressed, many oil and gas companies are expressing more interest in potential oil plays like the Brown Dense and the Tuscaloosa Marine Shale than in natural gas plays.

Below is a map that shows the relative locations of the Brown Dense, the Tuscaloosa Marine Shale, and the Haynesville Shale.

New York Issues Economic Assessment Report Regarding Hydraulic Fracturing

The New York Department of Environmental Conservation announced today its release of a a lengthy Economic Assessment Report that evaluates the economic effects that would result from the use of hydraulic fracturing within New York.  The DEC stated that its analysis "confirms that high-volume hydraulic fracturing activities could provide a substantial economic boost for the state in the areas of employment, wages and tax revenue for state and local governments."

The New York DEC estimated that the use of high volume hydraulic fracturing in New York would lead to the creation of over 17,600 full-time-equivalent construction jobs, more than 7100 jobs for individuals who will operate wells, and more than 29,100 indirect jobs (this is under an average scenario; the DEC also included low-range and high-range estimates).  The DEC concluded that the employee income from those jobs could be between $621.9 million and $2.5 billion per year.

The DEC estimated that hydraulic fracturing activity also would benefit state and local government.  "Using conservative tax rates at maximum build-out, the state could receive between $24 million and $125 million a year in personal income tax receipts."  In addition, the state could receive lease revenue from subsurface drilling beneath state lands.  The report DEC stated that use of hydraulic fracturing could result in increased use of some public services, such as roads, but implied that the increased cost to the state would be much less than the economic benefit.

The DEC estimated that increased tax revenue to local government also would be significant.  This could include "a substantial increase in sales tax receipts," as well as "an increase in ad valorem property tax revenue."

The DEC released the Economic Assessment Report today as an addition to its Supplemental Generic Environmental Impact Statement (SGEIS) that it issued earlier this Summer (see the July 9, 2011 post in the Oil & Gas Law Brief, which includes links to the SGEIS).  A public comment period on the SGEIS begins today and runs through December 12, 2011.  The DEC plans to issue proposed regulations in early October 2011, with a public comment period on the regulations running from the release of those regulations until December 12.  The DEC plans to hold four public hearings on the subject in different parts of the state, with specific locations and dates being announced in October.

The information released by the DEC today included: its announcement; a two-page Fact Sheet that summarizes economic impacts of hydraulic fracturing; a two-page Fact Sheet that summarizes local and community impacts; and the full, approximately 250-pages-long Economic Assessment Report.  

Montana Adopts Rule Requiring Disclosure of Composition of Hydraulic Fracturing Fluids

Montana's Department of Natural Resources and Conservation announced late last week the enactment of regulations that require operators to disclose information about hydraulic fracturing fluid on a well-by-well basis. 

After the well is completed, the operator must provide to Montana DNRC

  • a description of the formation fractured
  • the maximum pressure during fracturing
  • the amount and type of fluid used during fracturing 
  • a description of each fluid additive by type, such as biocide, corrosion inhibitior, friction reducer, proppant, etc.
  • the name of each chemical used (by Chemical Abstracts Number, which identifies a particular chemical, not just by trade name), and
  • the amount or concentration of each additive.

If the operator posts the required information on the website FracFocus, DNRC may waive all or a portion of the operator's duty to submit that information to DNRC.

In addition, the new regulations generally require an operator to include certain information in its application for a drilling permit in order for hydraulic fracturing to be allowed.  The information that an operator generally must include in its drilling permit application includes: the estimated total volume of fracturing fluid; the trade name or generic name of the principal components of the fracturing fluid; the estimated amount of the principal components of the fluid; the estimated weight of inert substances, such as proppants and other materials, contained in the fluid; and either the maximum estimated pressure during fracturing or certain information regarding the design of the well. 

The requirement to disclose this information in the drilling permit application does not apply for wildcat or exploratory wells or if an operator is unable to know in advance that it will need to conduct hydraulic fracturing as part of well completion, but for those wells the operator must provide the same information in a notice of intent to fracture that is provided to DNRC at least 48 hours in advance of the fracturing operation.

The regulations impose the same requirements for other types of well stimulation operations, such as acidizing.

The Montana DNRC Board of Oil and Gas Division has a web page on which it has links to the original proposed rule (discussed in the Oil & Gas Law Brief on June 7, 2011), the transcript of a public hearing on the proposal, all timely-submitted public comments, public comments that were submitted after the public comment period, a notice of adoption of the regulations, and the final text of the regulations.

Proposed Texas Regulation for Disclosure of Composition of Hydraulic Fracturing Fluids

The Texas Railroad Commission has issued a memorandum that includes the language of a proposed regulation to require disclosure of the composition of water used for hydraulic fracturing.  The proposed regulation would apply to wells for which the Commission issues the initial drilling permit on or after the effective date of the regulation, and would require suppliers and service companies to provide well operators with a list of each chemical intentionally added to the hydraulic fracturing fluid, and would require operators of wells to disclose

  • the date of hydraulic fracturing
  • the county in which the well is located, as well as the longitude and latitude of the well
  • the total vertical depth of the well
  • the total volume of water used in hydraulic fracturing (or the type and volume of the base fluid if the base fluid is not water)
  • each additive used in the hydraulic fracturing fluid, as well as the trade name of the chemical, and the supplier
  • the intended function of the chemical (for example, whether it is intended as a biocide, corrosion inhibitor, etc.), and
  • the concentration of each chemical.

The operator is required to supply this information for posting on the FracFocus website.  A supplier, service company, or operator need not disclose the identity of a chemical if the supplier contends that the chemical qualifies for trade secret under Texas Natural Resources Code, Section 91.851.  The standard for qualifying as a trade secret under that statute is based on the Restatement of Torts, Section 757, Comment B, as adopted by the Texas Supreme Court in Hyde Corp. v. Huffines, 314 S.W.2d 763, 776 (Tex. 1958). 

Factors that are considered under the standard adopted in that case include: (1) the extent to which information alleged to be a trade secret is known outside the company; (2) the extent to which the information is known by employees and others involved in the company's business; (3) the extent of the measures the company has taken to protect the secrecy of the information; (4) the value of the information to the company and its competitors; (5) the amount of effort or money expended by the company to develop the information; and (6) the ease or difficulty with which a person could properly acquire and develop the same information.

The proposed regulation provides a procedure for various persons to challenge a claim of trade secret status.  The persons who have a right to challenge a trade secret claim are: (1) the landowner on whose land the well-head is located; (2) the landowner of adjacent property; and (3) a state agency with jurisdiction over a matter to which a claimed trade secret is relevant.  The proposed regulation also requires disclosure to health care providers in certain circumstances.

 The proposed regulation, which would be designated as 16 Texas Administrative Code Section 3.29, was drafted in response to the Texas legislature's recent enactment (see this blog's June 6, 2011 post) of House Bill 3328, codified at Texas Natural Resources Code, Chapter 91, Subchapter S, Section 91.851, entitled "Disclosure of Composition of Hydraulic Fracturing Fluids."  As reported by this blog on June 6, 2011, that statute requires the Railroad Commission (the agency that regulates the oil and gas industry in Texas) to draft and implement regulations for disclosure of hydraulic fracturing fluids no later than July 1, 2013.  The Commission members have stated that they hope to finalize a regulation at least a year before that deadline.

In the memorandum accompanying the release of a draft regulation, the Commission's staff stated that permits were issued in 2010 for 15,466 new oil and gas wells in Texas, and that the Commission estimates that about 85 percent of those were hydraulically fractured.  The Commission noted that the website FracFocus, where many operators voluntarily post the composition of fracturing fluid, was launched on April 1, 2011, and that operators had posted information for nearly 950 wells in Texas as of August 16, 2011.   The Commission estimated that this amounted to about half the wells that were hydraulically fractured in Texas during that period.  Thus, the Commission estimates that operators already are disclosing fracturing water composition for about half of all new wells that are fractured.

The proposed regulation, which is now available on-line, likely will be published in the Texas Register on September 9, 2011.  The Commission will accept public comments through noon on Tuesday, October 11, 2011.  Comments may be submitted to Rules Coordinator, Office of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas, 78711-2697; by email to rulescoordinator@rrc.state.tx.us; or via on-line form at www.rrc.state.tx.us/rules/commentform.php.  Comments should refer to "O&G Docket No. 20-0272062." 

A public hearing regarding the proposed rule will be held on Wednesday, October 5, 2011 at 1:00 p.m., Central Daylight Time, at the Commission's headquarters at the William B. Travis State Office Building, 1701 N. Congress Avenue, Room 1-111, First Floor, Austin, Texas. 

The Commission stated that it anticipates that the new rule will have some adverse effects on suppliers, service companies, and operators because of the increased paperwork and reporting requirements, but the Commission estimates the costs "will be relatively minor."  The Commission also stated that the State will incur some administrative and enforcement costs.

Louisiana's Proposed Regulation for Disclosure of Fracking Water Composition Appears on Track for Enactment

As reported on July 11, 2011 in the Oil and Gas Law Brief, Louisiana's Department of Natural Resources has proposed a regulation that would require operators to disclose the composition of the water used to hydraulically fracture wells in Louisiana.  DNR has accepted public comments regarding the proposed regulation, and a public hearing regarding the proposal was held on August 30, 2011.  The comments, including those from industry, have been generally favorable, and the proposed regulation appears to be on track for enactment without any change in language.  Unless something unexpected happens, the regulation likely will go into effect in late October 2011.

As reported in this blog's July 11 post, the proposed regulation would require operators to disclose

  • the volume of hydraulic fracturing fluid used
  • the types of additives used (for example, biocides, corrosion inhibitors, friction reducers, etc.), as well as the volume of each type
  • the trade name and supplier of each additive, and 
  • a list of the chemical compounds contained in the additives, along with the maximum concentration of each compound.

If the identity of the chemical compound is a trade secret, the operator would be excused from identifying the compound, but would be required to identify the chemical family to which the compound belongs.

Louisiana's proposed regulation would require that the mandated disclosure be made either to the Office of Conservation or to FracFocus, a website operated by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission.  FracFocus posts information regarding fracturing fluid composition on a well-by-well basis, using information voluntarily submitted by operators. 

Ohio EPA Is Drafting General Permit for Air Emissions at Shale Gas Sites

The Ohio EPA recently announced that it is drafting a general permit to regulate air emissions from shale gas operations.  Like any other environmental permit, a general permit sets terms and conditions for a permit holder's operations, but the terms and conditions are standardized for all holders of a general permit, rather than developed on an individual basis for each permit applicant.

The general permit for shale gas operations will include:

  • emissions limits
  • operating restrictions
  • monitoring and testing requirements. 

The Ohio EPA stated that the general permit will cover various equipment used at shale gas sites, "including internal combustion engines, dehydration systems, truck-loading racks, storage tanks, flares and unpaved roadways."  The permit will not cover temporary activities that are exempt from existing air pollution permit regulations, such as the drilling and fracturing processes.

Ohio EPA explained that a general permit is appropriate because "most shale gas operations will be similar."  Ohio EPA noted that it's air division currently offers 47 types of general permits for various business sectors (Ohio EPA has a page on its website that describes its general permit program).  The Ohio EPA's announcement stated that development of a general permit for shale gas operations "will streamline the process" for obtaining a permit, enabling many applicants to obtain permits in as little as two weeks.

Ohio EPA has been accepting public comments on its proposal, and stated that it will consider those before developing a final draft of a general permit that it will issue for a 30-day comment period.  Ohio EPA expects to have a general permit for shale gas operations finalized and in effect by Fall 2011. 

The "Brown Dense" -- Another Potential Oil Play

The "Brown Dense" is the latest shale formation to generate excitement as a potential oil play.  The Brown Dense stretches across Southern Arkansas and into several parishes in North Louisiana, including Claiborne, Union, and Morehouse.

In a statement issued earlier today, Louisiana Department of Natural Resources Secretary Scott Angelle stated, "This is yet another opportunity for Louisiana to show that we can be an inviting and exciting province to do the business of finding and providing new sources of domestic energy that provide economic strength and opportunity for our state and nation." 

The Brown Dense is located at vertical depths from 8000 to 11,000 feet, and has a thickness that ranges from 300 to 550 feet.  The formation sometimes is called the Lower Smackover because it is located below the Smackover formation that has been a source of oil and gas production in North Louisiana and South Arkansas since the 1920s.

On July 28, 2011, Southwestern Energy issued an earnings report in which it announced that it has invested $150 million to acquire mineral rights in 460,000 acres to develop the formation.  Southwestern stated that it plans to begin drilling its first Brown Dense well in Columbia County, Arkansas late in the third quarter of 2011.  That well is expected to be drilled to a vertical depth of 8900 feet, with a horizontal lateral of about 3500 feet.  Southwestern plans to drill its second Brown Dense well sometime later in 2011 in Claiborne Parish, Louisiana.  The company expects that the second well will have a vertical depth of 10,700 feet and a 6000-foot horizontal lateral.  Southwestern stated that it could drill as many as 10 additional Brown Dense wells in 2012.

In an August 3, 2011 earnings call, Devon Energy announced that it has acquired minerals rights to 40,000 acres in North Louisiana for purposes of developing the Brown Dense formation, and that it expects to drill its first well to that formation in September 2011.  Devon will drill that well in Morehouse Parish.

Southwestern has a page on its website that provides additional details regarding the company's plans for the Brown Dense, and the terms of its leases. 

Department of Energy Recommendations Regarding Hydraulic Fracturing

A Department of Energy advisory panel recently issued a report regarding shale gas production and hydraulic fracturing.  The report identified benefits of those processes, but also noted various concerns and made several recommendations.  Prior posts in the Oil & Gas Law Brief discussed the benefits and the concerns discussed in the report.  This post discusses the recommendations made by the report, and notes some good news -- regulators and industry already are taking some of the actions recommended in the report.    

1. Recommendations Relating to Water Quality

The report acknowledges that most experts believe that there is relatively little risk that the underground fractures created by the fracturing process will serve as a pathway for contamination of underground sources of drinking water.  A greater concern is the possibility that well construction failures will allow contamination of drinking water aquifers.  To minimize the risk of well construction failures, the report recommends that companies and regulators adopt best practices in well construction techniques, including techniques for the casing and cementing of wells, and for testing the integrity of cementing jobs.  Ohio recently revised its well construction regulations, and other states are examining their existing regulations. 

The report also recommended the use of microseismic surveys to determine the extent of hydraulic fracture growth.  Although few (if any) people who have studied the issue believe that fractures will extend far enough to cause contamination of drinking water aquifers, many companies already are taking steps to monitor the extent of hydraulic fracture growth.

The report recommended that regulators require disclosure of the chemicals used in fracturing water, with protection for the identity of chemicals that qualify as actual trade secrets.  Wyoming, Arkansas, West Virginia, and Texas already have enacted disclosure requirements.  Louisiana regulators have proposed a mandatory disclosure regulation, and will hold a public hearing on the proposal tomorrow.  Montana regulators also have proposed such rules, and Michigan has enacted rules requiring operators to supply Material Safety Data Sheets to state regulators for the substances used in fracking.  Other states, including Colorado and New York are considering such regulations, and the federal government is considering such regulations for oil and gas drilling done on federal lands.  In addition, many companies have started voluntarily disclosing the composition of fracking fluid on the website FracFocus or on their own company websites.

The report recommended additional field studies to examine the possibility of methane leakage from shale gas wells to water reservoirs, and the adoption of a requirement for background testing of water wells prior to drilling of gas wells in an area.  Such field studies are part of the EPA's ongoing study of hydraulic fracturing.  Further, Pennsylvania has moved to require background testing of water wells prior to drilling of gas wells, and other states are considering such measures.

The report recommended eliminating the use of diesel as an additive to hydraulic fracturing fluid.  The EPA is moving to regulate (though not prohibit) such use. 

The report recommended the development of "green" drilling and fracturing fluids.  Some companies already have introduced "green" fracking additives that are drawn from substances that qualify as food additives.

2. Recommendations Relating to Air Quality

In order to promote improved air quality, the report recommended that companies and regulators implement efforts to reduce emissions of methane during drilling of wells, and subsequent production, post‑production treatment, and transport of natural gas.  So far, water issues have received the most attention from regulators, but the Department of Energy report noted that some states already have implemented regulations to reduce air emissions and that the United States EPA also recently proposed regulations to reduce air emissions. 

In addition to the measures noted above, the report recommended that companies make efforts to better measure emissions and that studies be made to estimate life cycle emissions for production, transport, and use of natural gas.

The report recommended reducing the use of diesel engines to power pumps and other equipment at drilling sites, and that natural gas engines or electric motors be used instead.

3. Other Recommendations

To minimize surface disturbances, the report recommends the use of multi‑well drill pads.  The report recommended efforts to mitigate noise, air and visual pollution, and traffic and congestion issues in the vicinity of drilling locations.  Some states, including Louisiana, already have enacted regulations to mitigate local disturbances.

The report recommended the sharing of technology by regulators and industry through the use of technology peer reviews and the creation of a shale gas industry group to develop best practices and standards.

The report recommended the creation of a national database that would link various existing sources of public information to make the information more easily accessible to the public. 

New Jersey Governor Chris Christie Vetoes Ban on Hydraulic Fracturing

Yesterday, New Jersey Governor Chris Christie conditionally vetoed a bill that would have made his state the first to ban hydraulic fracturing.  As reported in the Oil and Gas Law Brief on July 3, the New Jersey legislature passed the bill by wide margins in both the House and Senate.  In his veto message, Governor Christie recommended that the bill be revised to replace the proposed ban with a one-year moratorium on hydraulic fracturing.  

While I do share the sponsors' concerns about protecting our drinking water, I do not believe that the case has been made to justify a complete, permanent, statutory prohibition on fracking.  The legislative process revealed a substantial disagreement between those who favored a ban on fracking and those who opposed it.  Significantly, the bill was pushed through the legislature at the very same time that two federal agencies -- the Environmental Protection Agency (USEPA) and the Department of Energy (USDOE) -- were studying the environmental impact of this drilling technique."

Governor Christie stated that, "We must ensure that our environment is protected and our drinking water is safe."  But he also noted that shale gas production has substantial economic benefits.  Further, because gas is the cleanest burning of all fossil fuels, there are environmental benefits whenever shale gas is produced and used in place of coal.

In addition, I believe it would be premature and ill-advised to impose a permanent ban while the USDOE and USEPA are studying this issue and without the benefit of the views of the New Jersey Department of Environmental Protection (NJDEP).  Accordingly, based on all of these circumstances, I believe that the better approach to this issue is to impose a one-year moratorium on fracking in  New Jersey while the USDOE and USEPA continue to study fracking, and the NJDEP conducts an independent evaluation of the issue and reports its findings."

Governor Christie's veto message expressly acknowledged that some people have raised concerns that improperly cased gas wells could allow underground sources of drinking water to become contaminated, and he stated he has no doubts about the "good intentions of those who support this legislation, [but] I do not believe that the scientific grounds needed to justify an outright, permanent, statutory ban were established during the legislative process." 

A small portion of the Utica Shale, which is beneath the Marcellus Shale, extends into New Jersey, but there has not been any Utica Shale development in the state and no company has announced plans to drill there.

Governor Christie made his recommendation to amend the bill to impose a moratorium, rather than a permanent ban, in accordance with Article V, Section I, paragraph 14 of the New Jersey Constitution.  That provision states that a governor who chooses to veto a bill may veto the bill outright, or veto the bill with recommendations of changes to the bill that would make the bill acceptable to the governor.  The legislature may override a conditional veto by a two-thirds vote in order to enact the bill into law in its original form, or the legislature may enact the govenor's recommended changes by majority vote.  If the legislature does neither, the conditionally vetoed bill dies and does not become law.  

Responses to the veto have been mixed.  An industry publication, the Oil and Gas Journal, has reported that some supporters of shale gas development have expressed disappointment that Governor Christie did not veto the ban outright, while others were pleased with Governor Christie's attempt to replace the ban with a one-year moratorium.  Environmental groups have called for the legislature to override the conditional veto.

West Virginia DEP Announces Regulations for Hydraulic Fracturing

The West Virginia Department of Environmental Protection has announced issuance of regulations to govern hydraulic fracturing.  Among other things, the regulations will require that operators:

  • provide WVDEP with estimates of the amount of water they will use in drilling and fracturing their wells
  • develop and submit to WVDEP water management plans for any wells that they estimate will use more than 210,000 gallons of water during any one-month period
  • include in their water management plans information identifying the type of water source, such as surface or ground water, the specific location from which they anticipate withdrawing such water, the anticipated volume to be withdrawn, and when they anticipate withdrawing the water
  • identify all existing water uses within one mile downstream of a location where they will withdraw surface water, and ensure that enough in-stream flow remains to protect identified downstream uses
  • include in their water management plans the additives they anticipate using in their fracturing water, and (after completion of the well) provide a listing of the actual additives used 
  • record the quantity of flowback water, the quantity of produced water, and the method of management or disposal of the flowback and produced water
  • dispose of all drilling cuttings and drilling mud generated from wells that disturb more than three acres of surface or use more than 210,000 gallons of water during any one-month period at an approved solid waste facility, or manage such cuttings and drilling mud on-site in a manner approved by WVDEP
  • construct their wells in conformance with casing standards and cementing standards published by the American Petroleum Institute
  • develop erosion and sediment control plans for any well site that will disturb three or more acres of surface, and
  • publish a public notice at least 30 days in advance of the issuance of a permit to drill the first well from any particular well pad that is located within the boundaries of any municipality.

Governor Earl Ray Tomblin requested that WVDEP prepare hydraulic fracturing regulations in his Executive Order 4-11 on July 12, 2011 (as reported in this blog on July 19).  The regulations were promulgated under WVDEP's emergency powers, which allowed for the regulations to be developed and put into effect more quickly than under the standard rule-making process.  Governor Tomblin's Executive Order indicates that the regulations are intended to govern hydraulic fracturing in West Virginia pending further action from the state legislature.

Hydraulic Fracturing Litigation: Nuisance and Breach of Contract Claims

More and more plaintiffs are filing lawsuits in which they claim that their drinking water has been contaminated by hydraulic fracturing operations.  The Oil and Gas Law Brief began a series of posts discussing this topic about a month ago.  Prior posts have provided an introduction to hydraulic fracturing litigation (July 18) and discussed claims based on an abnormally dangerous activity legal theory (July 25), defenses to claims based on an abnormally dangerous activity theory (July 29), and claims based on subsurface trespass (August 1). 

1.                  Nuisance

"A private nuisance is a nontrespassory invasion of another's interest in the private use and enjoyment of land."  See Restatement (Second) Torts § 821(D). The pollution of surface or ground waters can constitute a private nuisance.  See id. at § 832  For a defendant to have liability for a private nuisance, his invasion of the plaintiff's interest must be either (a) "intentional and unreasonable," or (b) actionable under rules controlling liability for negligence or abnormally dangerous activity.  See id. at § 822.  An invasion of the plaintiff's interest is considered intentional if the defendant acts for the purpose of causing the invasion of interest, or he knows that his actions are causing the invasion, or he knows that his actions are substantially certain to do so.  See id. at § 823 

To defeat a nuisance claim, a defendant should concentrate on demonstrating that it did not intend the alleged invasion and did not know that the alleged invasion was substantially certain to occur.  The defendant should also argue that its conduct was not unreasonable.  If a defendant conducted its activity in compliance with a permit issued by regulators, the defendant should point to that as evidence of its reasonableness.  The defendant also can point to the value that hydraulic fracturing provides to the community -- jobs, tax revenue, a decreased dependence on foreign sources of energy, and the production of a clean burning fuel. 

To the extent the plaintiff argues that the defendant is liable for private nuisance because the defendant's conduct would be actionable under theories of nuisance or strict liability for an abnormally dangerous activity, a defendant would defend against such a nuisance claim in the same way that he would defend against claims brought under negligence or strict liability theories.

2.                  Breach of contract

Oil and gas well operators typically operate pursuant to a mineral lease with the person holding mineral rights to the land on which the well is drilled (the mineral rights owner may or may not be the landowner).  In addition to the mineral lease, the oil and gas company may have a surface use agreement with the landowner.  These contracts may contain clauses which would give the landowner a basis to bring suit in the event his land or groundwater beneath his land were contaminated.  In addition, courts typically impose upon mineral lessees various implied covenants that require lessees to conduct their activities as reasonably prudent operators.  This standard of conduct sounds very much like a negligence standard, and a landowner could assert a claim based on an argument that a lessee breached an implied covenant to act as a reasonably prudent operator by causing contamination of the landowner's property or the groundwater beneath it. 

If a plaintiff alleges that the defendant breached an implied covenant by negligently allowing fracturing to cause contamination, the defendant should argue that the plaintiff's claim sounds only in tort.  A few decisions have held that a plaintiff may assert an implied covenant claim based on the defendant allegedly causing or allowing an accident.  See, e.g., Empire Oil & Refining Co. v. Hoyt, 112 F.2d 356 (6th Cir. 1940).  But there are not many such cases.  Generally, implied covenants are used to ensure that lessees are diligently exploring for and producing minerals.  See generally Keith B. Hall, The Continuing Role of Implied Covenants in Developing Leased Lands, 49 Washburn L.J. 313 (2010). 

Implied covenants are imposed by courts in the context of oil and gas leases more frequently than in the context of other types of contracts because of a particular characteristic of oil and gas leases.  Namely, because of the uncertainties involved in mineral exploration, oil and gas leases generally do not specify in detail the exploration and production activities the lessee will conduct.  See Keith B. Hall, Implied Covenants:  Claims Under Article 122, 57 Min. L. Inst. 172, 173-4 (2010).  Thus, some of the most important aspects of a lessee's performance are left to his discretion.

Because so much is left to the discretion of the lessee, courts impose implied covenants to protect the lessor by requiring the lessee to be reasonably diligent in exploration and development.  See id.; see also Patrick H. Martin, A Modern Look at Implied Covenants to Explore, Develop, and Market Under Mineral Leases, 27 Sw. Legal Fdn. Oil & Gas Inst. 177, 194 (1976).  But implied covenants are not needed to guard against negligent conduct because negligence law already does that.  Accordingly, if the factual basis of a lessor's claim is the alleged negligence of the lessee, the lessee can argue that such a claim sounds in tort and that it does not constitute a breach of contract claim. 

A future post will discuss the types of expert witnesses the parties may need in hydraulic fracturing litigation.

Carnegie Mellon Study on Life Cycle Greenhouse Gas Emissions for Shale Gas Reaches Different Conclusions than Cornell Study

A group of researchers from Carnegie Mellon have released a study that estimates the "life cycle" greenhouse gas emissions for Marcellus shale gas.  The "life cycle estimates" are estimates of the total amount of greenhouse gas emissions for all activities associated with the production, treatment, transport, and ultimate use of shale gas for electricity production.  The researchers compared their life cycle estimates for Marcellus shale gas to similar estimates for coal and for natural gas produced by conventional means.  In contrast to the conclusions reached by a Cornell study, the Carnegie Mellon researchers concluded that Marcellus shale gas has life cycle greenhouse gas emissions that generally are significantly lower than the life cycle emissions for coal, and that are only slightly higher than those for natural gas produced from conventional wells that are not hydraulically fractured.

The Carnegie Mellon researchers estimated emissions for three greenhouse gases -- carbon dioxide, methane, and nitrous oxide -- and converted those emissions to "carbon dioxide equivalents" using the 100-year global warming potential (GWP) factors reported by the Intergovernmental Panel on Climate Change (IPCC).  The conversion is made because each type of greenhouse gas has a different amount of global warming potential.  For example, a molecule a methane is estimated to have 25 times more global warming effect than a molecule of carbon dioxide.  Thus, a molecule of carbon dioxide would count for one carbon dioxide equivalent, while a molecule of methane would count for 25 carbon dioxide equivalents. 

The "100-year" reference refers to the fact that the global warming effect is based on the global warming effect that emissions will have after 100 years have passed.  A specific time horizon must be chosen because methane will breakdown in the atmosphere over time, thereby decreasing its greenhouse gas effect over time.  Thus, the immediate greenhouse gas potential is different than that which will remain after 20 years, which is different than that which will remain after 100 years.  The 100-year greenhouse gas potential is used to obtain long range estimates of the greenhouse gas effect of emissions.  

The Carnegie Mellon researchers attempted to be comprehensive in the activities they chose to include in their life cycle analysis.  They included estimated emissions for various parts of the pre-drilling and pre-production process, including emissions from the operation of equipment used in constructing the well pad, equipment used in the drilling process, motors used in pumping fracturing fluid into the well for the fracking process itself, and trucks used is delivering water to the drill site for fracturing, as well as emissions associated with producing drilling mud, emissions from the process of venting or flaring during flowback and well completion, fugitive emissions that occur during treatment and transport of shale gas, and emissions from combustion when the gas ultimately is used to generate electricity in a power plant. 

The Carnegie Mellon researchers concluded that the life cycle greenhouse gas emissions for Marcellus shale gas emissions are about 3% higher than for natural gas produced from conventional wells, and are about 3% lower than liquefied natural gas imported to the U.S.  They estimated that the life cycle emissions for the use of Marcellus shale gas in power generation are much lower than for the use of domestic coal is most scenarios.  The one exception is a scenario in which one assumes that a power plant uses advanced carbon capture and sequestration (CCS) technology.  If CCS is used for both a natural gas-fired power plant and a coal-fired power plant, the estimated life cycle emissions for coal are slightly lower than for Marcellus shale gas.

The Carnegie Mellon researchers did not assume that so-called "green" completions or "reduced emissions" completions would be used during flowback and completion of a Marcellus well.  Such techniques would reduce emissions.  A couple of western states now require green completions, and some companies voluntarily are using green completions.  Further, the EPA has proposed regulations that would require green completions starting in March 2012.  If the Carnegie Mellon researchers had assumed that green completions are used, their estimates of life cycle greenhouse gas emissions for Marcellus shale gas would be closer to the life cycle estimates for natural gas produced from conventional wells, and would compare even more favorably relative to coal than when it is assumed that green completions are not used.

The Carnegie Mellon researchers' results contrast with those of a study by Cornell researchers, who concluded that shale gas has higher life cycle greenhouse gas emissions than those for the use of coal, whether one looks at a 20-year time horizon or a 100-year time horizon.

The Carnegie Mellon study was funded in part by the Sierra Club.

Hydraulic Fracturing: Concerns Expressed in Department of Energy Report

A United States Department of Energy advisory panel recently issued a report on issues relating to shale gas production, including the use of hydraulic fracturing.  That report of the Shale Gas Subcommittee of the Secretary of Energy Advisory Board identified several benefits of shale gas production and hydraulic fracturing, but also discussed several concerns relating to shale gas production, and made recommendations to address those concerns.  This blog's August 15 post discussed the benefits identified in the report.  As to concerns, the report stated:

The Subcommittee identifies four major areas of concern:  (1) Possible pollution of drinking water from methane and chemicals used in fracturing fluids; (2) Air pollution; (3) Community disruption during shale gas production; and (4) Cumulative adverse impacts that intensive shale production can have on communities and ecosystems."

(1) Possible Pollution of Drinking Water

The Subcommittee concluded that one of the most common worries about hydraulic fracturing relates to a type of event that is unlikely to occur.  The Subcommittee explained:  "One of the commonly perceived risks from hydraulic fracturing is the possibility of leakage of fracturing fluid through fractures into drinking water.  Regulators and geophysical experts agree that the likelihood of properly injected fracturing fluid reaching drinking water through fractures is remote when there it is a large depth separation between drinking water sources and the producing zone.  In the great majority of regions where shale gas is being produced, such separation exists and there are a few, if any, documented examples of such migration." 

The Subcommittee shares the prevailing view that the risk of fracturing fluid leakage into the drinking water sources through fractures made in deep shale reservoirs is remote." 

The report stated that if a water well becomes contaminated, it is less likely to be contaminated with fracturing fluid than with methane, the principal component of shale gas ("shale gas" is sometimes used in referring to natural gas produced from shale).  The report concluded that, "Methane leakage from producing wells into surrounding drinking water wells, exploratory wells, production wells, abandoned wells, underground mines, and natural migration is a greater source of concern."  

The report stated, though, that if a water well is contaminated with methane, the contamination is not necessarily the result of fracturing.  "The presence of methane in wells surrounding a shale gas production site is not ipso facto evidence of methane leakage from the fractured producing well since methane may be present in surrounding shallow methane deposits or the result of past conventional drilling activity." 

And, if a hydraulically fractured well is the cause of contamination, the pathway for flow of contaminants is less likely to be fractures created in shale during the fracturing process than it is to be a pathway that results from a well construction failure -- specifically, a poor casing or cementing job.  In fact, noted the report, a poorly cased and cemented well could potentially leak "regardless of whether the well has been hydraulically fractured."  

The report stated that surface spills also potentially could cause contamination of shallow drinking water formations.  But the potential for contamination from surface spills is a hazard that is not unique to the fracturing process, or to the oil and gas industry.  Our society uses a number of hazardous chemicals in a variety of industries. 

(2) Air Pollution

The Subcommittee noted two air pollution concerns.  One relates to emissions from the use of diesel engines for various purposes, including running pumps, at the fracturing site.  The report suggested that gasoline engines or electric motors could be substituted for diesel engines.  A second air pollution concern is leakage or emissions of methane during drilling and during the subsequent production, processing, and transport of natural gas.  The report explained that methane emissions are a concern because methane is a more potent greenhouse gas than carbon dioxide.  Regulators and industry already are addressing this concern, as will be discussed in more detail in a future post by this blog discussing the report's recommendations.

(3) Community disruptions and (4) Cumulative Impacts

The report expressed concern about traffic congestion and other issues that can arise from actions that are not disruptive or problematic individually, but which cumulatively can have a disruptive effect when such actions are repeated many times.

Other Concerns Identified in Report

In addition to the four main concerns discussed by the report, the report noted that water supply issues sometimes can be a problem.  The report notes that hydraulic fracturing of a typical shale gas well requires between 1 and 5 million gallons of water.  The report states that, "While water availability varies across the country, in most regions water used in hydraulic fracturing represents a small fraction of total water consumption.  Nonetheless, in some regions and localities there are significant concerns about consumptive water use for shale gas development."

The report noted that proper disposal of flowback water also sometimes is an issue.  The report noted that one way to deal with flowback is to recycle it for use as part of the fracturing fluid in future frack jobs.  This reduces the amount of flowback that requires disposal, and reduces the amount of new water which must be supplied.  Companies are using such recycling on a more frequent  basis.

Report's Observation about the Public Debate

The Subcommittee's report also made observations about the seemingly conflicting claims of proponents and opponents of hydraulic fracturing.  The report notes that supporters of hydraulic fracturing state that it has been performed safely without significant incident for over 60 years, and the report acknowledges that the supporters of fracking have a point. 

Opponents point to failures and accidents and other environmental impacts, but these incidents are typically unrelated to hydraulic fracturing per se and sometimes lack supporting data about the relationship of shale gas development to incidence and consequences." 

But the report suggested that supporters' references to the lack of documented problems caused by fracking will not win the public relations battle, and that some opponents do point to real problems, even if the problems generally do not arise from the fracking process itself.  The report observed that proponents and opponents look at a different scope of activities in judging hydraulic fracturing.   

The report states:  "Some of this difference in perception can be attributed to communication issues.  Many in the concerned public use the word 'fracking' to describe all activities associated with shale gas development, rather than just the hydraulic fracturing process itself.  Public concerns extend to accidents and failures associated with poor well construction and operation, surface spills, leaks at pits and empowerments, truck traffic, and the cumulative impacts of air pollution, land disturbance and community disruption." 

The Subcommittee stated that some of its observations perhaps could be extended to other types of oil and gas operations, but that the Subcommittee intended to focus on shale gas development and that the Subcommittee "caution[s] against applying our findings to other areas, because the Subcommittee has not considered the different development practices and other types of geology, technology, regulation and industry practice."

In a subsequent post, this blog will discuss the report's recommendations, some of which are steps that regulators already are being taken by regulators. 

West Virginia Court Strikes Down a City's Ban on Hydraulic Fracturing

A state court judge in West Virginia has struck down an ordinance enacted by the City of Morgantown to ban hydraulic fracturing within the City and anywhere within one mile of the City.  The case was filed by Northeast Natural Energy, LLC, which previously had received a permit from the West Virginia Department of Environmental Protection to drill and hydraulically fracture a Marcellus Shale well in an area outside the city limits of Morgantown, but within one mile of the City.  Northeast had not yet hydraulically fractured the well when the ordinance went into effect.  Northeast argued to the court that the City's ordinance was preempted by state law and therefore was unenforceable. 

The case was assigned to Judge Susan Tucker, who granted summary judgment in favor of Northeast on August 12, 2011.  Her opinion discussed the concept of preemption, explaining that when state legislation "fully occupies" a particular subject area, establishing a "comprehensive regulatory scheme," no local ordinance can contravene that state law.  To determine whether state law would preempt local laws regulating hydraulic fracturing, Judge Tucker examined state statutes relating to environmental protection and regulation of the oil and gas industry.

Judge Tucker noted that West Virginia statutes declare that "The state has the primary responsibility for protecting the environment; other government entities, public and private organizations and our citizens have the primary responsibility of supporting the state in its role as protector of the environment."  Another statute declares that the purpose of the West Virginia Department of Environmental Protection ("WVDEP") is to "consolidate environmental regulatory programs in a single agency, while also providing a comprehensive program for the conservation, protection, exploration, development, enjoyment and use of the natural resources of the state of West Virginia."  State law also requires the Director of the WVDEP to maintain an office of oil and gas under his supervision, with that office being charged with a duty of administering and enforcing the West Virginia Oil and Gas Act.  In addition, a state statute indicates that it is within the sole discretion of the WVDEP to perform all duties relating to the exploration, development, production, storage, and recovery of West Virginia's oil and gas.

Judge Tucker determined that these statutes demonstrate that West Virginia has enacted a comprehensive state regulatory program that will preempt any local ordinance that is inconsistent with state law, rendering such local ordinances invalid.  In this case, the local ordinance enacted by Morgantown was inconsistent with state law because the local ordinance would ban certain drilling and hydraulic fracturing altogether, even if the processes are authorized by WVDEP.  Therefore, the ordinance was invalid.  The case is Northeast Natural Energy, LLC v. City of Morgantown, Civil Action No. 11-C-411, Circuit Court of Monangalia County.

Similar issues can arise in other states, many of which have statutes that attempt to make a state regulatory agency the sole (or at least the primary) body that regulates the oil and gas industry.  For example, Louisiana law requires a person to obtain a permit from the Office of Conservation before drilling a well, and provides that Conservation's grant of a permit will constitute "sufficient" authority to drill.  Another state statute expressly states that "[n]o other agency or political subdivision of the state shall have the authority, and they are hereby expressly forbidden, to prohibit or in any way interfere with the drilling of a well or test well in search of minerals by the holder of such a permit."  In 2006, the United States Fifth Circuit held that the ordinance completely preempted and therefore rendered unenforceable a Shreveport ordinance that attempted to bar drilling within 1000 feet of a lake that served as the source of drinking water, and to regulate drilling that occurred further away.  See Energy Management Corp. v. Shreveport, 397 F.3d 297 (5th Cir. 2006).

The extent to which local governments may prohibit or regulate oil and gas drilling will differ from one state to another, but in many states the authority of local governments is significantly restricted in this subject area by state laws such as those in West Virginia and Louisiana, which attempt to establish a comprehensive regulatory program for oil and gas that is overseen by a single state agency.

Department of Energy Panel Confirms Benefits of Hydraulic Fracturing and Shale Gas Production, But Recommends Changes

Late last week, a United States Department of Energy advisory panel announced the release of its initial report on shale gas development and hydraulic fracturing.  The report discussed benefits of shale gas production, as well as concerns about such production, and made several recommendations.

The panel identified the same three types of benefits previously discussed in this blog -- (1) economic benefits, (2) national security benefits, and (3) environmental benefits.

The economic significance is potentially very large.  While estimates vary, well overt [sic] 200,000 jobs (direct, indirect, and inducted) have been created over the last several years by the development of domestic production of shale gas, and tens of thousands more will be created in the future."

Further, the report notes that increased supplies have contributed to reductions of more than 50% in the price of natural gas "since 2008, benefiting consumers in the lower cost of home heating and electricity."

The panel concluded that shale gas production will reduce the country's dependence on imported natural gas, and perhaps even imported oil, thereby providing important national security benefits. 

As late as 2007, before the impact of the shale gas revolution, it was assumed that the United States would be importing large amounts of liquefied natural gas from the Middle East and other areas.  Today, the United States is essentially self-sufficient in natural gas, with the only notable imports being from Canada, and is expected to remain so for many decades."

Further, "Domestic production of shale gas also has the potential over time to reduce dependence on imported oil for the United States."  This would be beneficial because a significant portion of imports come from politically unstable areas, including areas sometimes hostile to the United States.  A similar benefit applies as to the country's foreign allies: "International shale gas production will increase the diversity of supply for other nations.  Both these developments offer important national security benefits."

Finally, the report noted that shale gas production has potential environmental benefits because natural gas is the cleanest burning of all fossil fuels.  The report stated that shale gas "offers climate change advantage because of its low carbon content compared to coal."

The report, dated August 11, 2011, was issued by the Shale Gas Subcommittee of the Secretary of Energy Advisory Board.  In later posts, this blog will discuss the concerns raised in the report, as well as the recommendations contained in it.

Will EPA's Proposed Air Rules for Fracking Make the Cornell Study Moot?

Proponents of hydraulic fracturing argue that fracking has several benefits (see my April 1, 2011 post), including an environmental benefit.  The environmental benefit is that fracking often is used to produce natural gas, the cleanest burning of all fossil fuels.  On an energy equivalent basis, the combustion of natural gas produces only half as much carbon dioxide as does coal, and it also produces less particulate matter, sulfur dioxide, and nitrous oxides.  Thus, to the extent that the use of natural gas displaces the use of coal, hydraulic fracturing can be good for air quality and for the effort to curb climate change.  

But earlier this year, a study released by Cornell researchers challenged the notion that the use of natural gas produced from shale will result in lower emissions of greenhouse gases.  The study concedes that natural gas is clean burning, but concludes that the production of natural gas from shale results in large releases of methane during the fracturing process, and in particular during the recovery of flowback water.  Methane is the principal component of natural gas and, like carbon dioxide, is a greenhouse gas.  In fact, methane has a stronger greenhouse gas effect than carbon dioxide (though, in the long run, the methane will break down in the atmosphere).

The Cornell study was based on the assumption that natural gas that accompanies flowback would be vented to the atmosphere, not recovered or flared.  Critics of the Cornell study questioned that assumption, and now the EPA has proposed new air rules (see my post on this subject) that generally will require recovery of natural gas that accompanies flowback.  

In certain circumstances in which recovery is not practical, the proposed new rules would require flaring, rather than venting.  In flaring, the natural gas that otherwise would be vented is burned.  The flaring results in emissions of carbon dioxide, but the greenhouse gas effect of that carbon dioxide is less than that of the natural gas that would be vented if it were not flared.  Thus, flaring generally is preferable to venting. 

The proposed new rules may moot the concerns raised by the Cornell study and convince more people that hydraulic fracturing can have environmental benefits.

EPA Proposes New Air Rules for Hydraulic Fracturing and for the Oil and Gas Industry

On July 28, 2011, the EPA announced a proposal for four new regulations and a new source performance standard to reduce the emissions of methane and volatile organic compounds ("VOC") from the oil and gas industry.  One of the new regulations specifically addresses hydraulic fracturing.  The EPA's proposals address five types of sources.  The EPA released a "Fact Sheet" and a slide presentation that included the following information.

Hydraulic fracturing                                           

  • Companies would be required to minimize VOC emissions by using "green completions," also called "reduced emissions completions," in which equipment is used to separate gas and liquid hydrocarbons from the flowback water that comes from the well after hydraulic fracturing.
  • After separation from flowback, the gas and hydrocarbons can then be recovered, treated, and sold.
  • Some states, such as Wyoming and Colorado, require "green completions," and a number of companies are voluntarily using this process through EPA's Natural Gas STAR program. 
  • EPA estimates that use of "green completions" after hydraulic fracturing will reduce VOC emissions from completions and recompletions of hydraulically fractured wells by 95 percent.
  • When gas cannot be collected, VOCs would be reduced through pit flaring, unless it is a safety hazard.
  • Methane, a potent greenhouse gas, also would be significantly reduced as a co‑benefit of reducing VOCs.
  • The green completion requirements would not apply to exploratory wells or delineation wells (used to define the borders of a natural gas reservoir), because they are not near gas sales lines.  Those wells must use pit flaring to burn off their emissions, unless it is a safety hazard.

Compressors

  • Compression is necessary to move natural gas along a pipeline.  Centrifugal compressors would have to be equipped with dry seal systems in order to reduce VOC emissions.
  • Owners/operators of reciprocating compressors would have to replace rod packing systems after every 26,000 hours of operation.

Pneumatic controllers

Pneumatic controllers are automated instruments used for maintaining a condition such as liquid level, pressure, and temperature at wells, gas processing plants, compressor stations, among other locations.  These controllers may release natural gas (including VOCs and methane) with every valve movement, or continuously in some cases.

EPA is proposing VOC emission limits for pneumatic controllers. 

  • For new or replaced pneumatic controllers at gas processing plants, the proposed limits would eliminate VOC emissions.  These limits could be met through using controllers that are not gas‑driven.
  • For controllers used at other sites, such as compressor stations, the emission limits could be met by using controllers that emit no more than six cubic feet of gas per hour.
  • The proposed amendments include exceptions for controllers in applications requiring high‑bleed controllers for certain purposes, including operational requirements and safety.

Condensate and crude oil storage tanks

  • Tanks with a throughput of at least 1 barrel per day of condensate or 20 barrels per day of crude oil must reduce VOC emissions by 95 percent.

Natural gas processing plants

  • EPA is proposing to amend the existing new source performance standards ("NSPS") for natural gas processing plants to strengthen the leak detection and repair requirements that apply to these plants to reduce VOC emissions.

Benefits and Costs Anticipated by the EPA

EPA estimates the following combined annual emission reductions when the proposed amendments are fully implemented:

  • VOCs:  540,000 tons, an industry‑wide reduction of 25 percent
  • Methane ─ 3.4 million tons, which is equal to 65 million metric tons of carbon dioxide equivalent (CO2e), a reduction of about 26 percent.
  • Air Toxics ─ 38,000 tons, a reduction of nearly 30 percent.

EPA estimates that compliance with the proposed rules will yield a net savings to the industry as a whole.  EPA estimates complying with all of the proposed requirements would cost industry an additional $754 million in 2015.  But compliance will avoid the loss (through venting or flaring) of natural gas and condensate with an estimated value of $783 million, making those products available for sale so that industry sees a net savings of $29 million, though the estimated costs and savings would not be distributed uniformly.

The Litigation that led to the Proposed Rules

In January 2009, WildEarth Guardians and the San Juan Citizens Alliance sued EPA, alleging that the Agency had failed to review the new source performance standards and air toxic standards for the oil and natural gas industry.  In February 2010, the U.S. Court of Appeals for the D.C. Circuit entered a consent decree that requires EPA to sign proposals related to the review of these standards.  EPA must issue final standards by February 28, 2012.

Comments

The EPA is accepting comments on the proposed rules 

Study Discusses Effect of Shale Gas on U.S. National Security

The James A. Baker III Institute for Public Policy at Rice University has released a study titled "Shale Gas and U.S. National Security."  The study, dated July 2011, concludes that shale gas -- natural gas produced from shale formations -- will have significant, beneficial impacts on the U.S. economy and national security. 

The study notes that shale gas production has reduced the United States' requirements for imported liquefied natural gas (LNG), thereby freeing up additional supply for Europe.  The study states that already this "has played a key role in weakening Russia's ability to wield an 'energy weapon' over its European customers by increasing alternative supplies to Europe in the form of LNG displaced from the U.S. market."

The dramatic lessening of Europe's dependence on Russian gas will likely reduce Russia's ability to unduly influence political outcomes.  European buyers will have ample alternatives to Russian supplies, thereby reducing Moscow's leverage on the balance of power between Russia and the EU."

The study suggests that the unwillingness of some European countries to condemn Russia's invasion of Georgia, and Germany's opposition to putting the Ukraine on a path toward NATO membership may be influenced by the current dependence of Europe on Russian gas, but that such dependence will diminish in the future, making it easier for the U.S. to gain European support for international policies that are opposed by Russia.

The study concludes that shale gas will also help reduce the influence of other nations that sometimes have been a problem for U.S. foreign policy: "Specifically, shale gas will play a critical role in diminishing the petro-power of major natural gas producers in the Middle East, Russia, and Venezuela and will be a major factor limiting global dependence on natural gas supplies from the same unstable regions that are currently uncertain sources of the global supply of oil."

One of the nations discussed in the report is Iran.  International sanctions have hampered Iran's ability to build significant natural gas export capabilities, and shale gas production in the U.S. will increase global supplies of natural gas, further delaying Iran's ability to develop export capabilities.

Rising U.S. shale gas supplies will also assist the United States in its policies toward Iran.  Given global market economics under a full development of shale scenario, the commercial window for Iran to export large amounts of natural gas is likely to be closed for an additional 20 years, making it easier for the United States to achieve buy-in for continued economic sanctions against Iran.  Shale gas development lowers the chances that Iran can use its energy resources to drive a wedge in the international coalition against it."

The report concludes that delaying the world's need for Iranian gas also increases the chance that political change will take place in Iran before the country can gain influence and support its nuclear ambitions by becoming a major supplier of natural gas to other countries.  Further, it lessens the likelihood that Iran can develop an Iran-to-India pipeline, which, if completed, would be a source of tension between the U.S. and India.

The report concludes that China will have to increase its imports of natural gas significantly in future years as its demand grows, but that increased production of shale gas in the U.S. will lessen China's dependence on natural gas from the Middle East.  And, by also reducing the dependence of the U.S. on sources of natural gas from the Middle East, the increased production of shale gas will decrease the incentive for geopolitical competition between the U.S. and China. 

The report concludes that China will need to import more gas from Russia even with the development of shale gas in the U.S., which will lead to the strengthening of ties between  China and Russia.  But, by implication, the report suggests that the need for China to import gas from Russia will be less with the production of shale gas in the United States than without such production.

The Baker Institute study was supported by the United States Department of Energy. 

Shale Plays Affect Pipeline Economics

The development of shale plays is having significant effects on pipeline use and availability.  The latest example is an announcement by Shell Pipeline that it is considering reversing the direction of flow in its Houma-to-Houston pipeline, which sometimes is called the "Ho-Ho."  The pipeline currently is used to transport product from east to west, but Shell is considering reversing that in order to service the increased supply of oil from such shale plays as the Eagle Ford and Bakken.  If the switch is made, Shell anticipates that the new service, which would be subject to regulatory approval, would begin in early 2013 and could transport approximately 300,000 barrels of crude per day.

Chesapeake Claims Utica Contains Tremendous Amounts of Oil

Chespeake has announced that the portion of the Utica Shale located beneath Eastern Ohio contains large quantities of oil and natural gas liquids.  In an interview with Jim Cramer on "Mad Money," Chesapeake's Aubrey McClendon compared the Utica Shale to Eagle Ford, but said that the Utica Shale might be even better.

The Utica Shale, which is found below the Marcellus Shale, covers a large portion of the Eastern United States, as is shown on an Energy Information Administration map, as well as a map that accompanies an article at geology.com.  

Ohio Governor John Kasich announced that he is thrilled by the prospect for the job creation that will accompany development of the Utica Shale in Ohio.

Shale plays that produce oil, including the Eagle Ford and Bakken, as well as emerging shale plays such as the Utica and Tuscaloosa Marine Shale, could greatly reduce this country's dependence on foreign sources of oil

Hydraulic Fracturing Litigation -- Trespass Claims

My July 18, 2011 post noted that, in most hydraulic fracturing litigation, plaintiffs assert claims based on multiple legal theories, including trespass.

A trespass occurs if the defendant makes an unauthorized entry onto the plaintiff's property or causes a thing to make an unauthorized entry.  See Restatement (Second) Torts § 158.  It is well‑established that a trespass can occur by the unauthorized entry into the subsurface of the plaintiff's property.  See id. at § 159; Gliptis v. Fifteen Oil Co., 16 So. 2d 471 (La. 1944).  If a trespass is intentional, a defendant can be liable even if the plaintiff cannot show harm.  See Restatement (Second) Torts § 158. 

But if a trespass is not intentional, and the defendant's activity was not ultrahazardous, the plaintiff must show actual harm in order to recover.  See id. at § 165.  It will not be enough for the plaintiff merely to show that a substance has encroached upon his land.  And, if the physical intrusion is neither intentional nor the result of negligence, the plaintiff will not be entitled to recover even if he can show injury.  See id. at § 166.  Thus, if an intrusion onto plaintiff's property was not intentional, a defendant can avoid liability unless the plaintiff can prove negligence and actual damages. 

Various other defenses might also apply, including one based on the "rule of capture."  The rule of capture is an oil and gas doctrine.  It provides that if a landowner drills a well on his property, and the well does not trespass onto his neighbor's property, then the landowner is entitled to all the oil or gas produced by his well, even if the well drains oil or gas from beneath his neighbor's property.  See Kelly v. Ohio Oil Co., 49 N.E. 399 (Ohio); see also Patrick H. Martin and Bruce M. Kramer, Manual of Oil and Gas Terms (14th ed. 2009).

In Coastal Oil & Gas v. Garza Energy Trust, 258 S.W.3d 1 (Tex. 2008), the plaintiff alleged that the defendant drilled a well on neighboring property, and that the fracturing fluid and proppants(but not the well bore) encroached into the subsurface of the plaintiff's property.  The plaintiff alleged that the encroachment constituted a trespass, and that the trespass harmed plaintiff by facilitating the drainage of minerals from beneath the plaintiff's land.  The Texas Supreme Court held that, because the only harm alleged by the plaintiff was drainage, the rule of capture precluded recovery.  Accordingly, the court did not have to decide whether the intrusion of fracturing fluid would have constituted an actionable trespass if there had been some harm other than drainage.

In some cases, unitization might provide a defense.  Unitization is a regulatory action or contractual agreement that modifies the rule of trespass by providing that all landowners holding property within a particular unit area will share in production of any oil or gas produced from within the unit, without regard to where the well is drilled.  See, e.g., Hunter Co., Inc. v. McHugh, 11 So. 2d 495 (La. 1943).  Unitization modifies property rights by displacing the rule of capture.  In Wainoco v. Nunez, 488 So. 2d 955 (La. 1986), the plaintiff's land had been unitized withthe neighbor's land.  A well was drilled from a well pad on the neighboring property, but the drilling deviated form vertical (apparently, unintentionally), and the well allegedly intruded into the subsurface of the plaintiff's land at some deep depth.  The plaintiff alleged a trespass, but the Louisiana Supreme Court held that the unitization order modified property rights, with the result being that plaintiff did not have a claim for subsurface trespass.

Finally, if the defendant has operated pursuant to government‑issued permits, that may provide a defense to a trespassing claim.  In several cases, plaintiffs have complained that fluids from an injection disposal well on neighboring property have intruded into the subsurface of plaintiff's land.  Courts generally denied recovery in those cases.  Although those courts generally have based their holdings on a plaintiff's inability to show actual harm, the language of the opinions also suggest that courts are reluctant to hold a defendant liable for actions he undertook pursuant to a valid permit.  See, e.g., Chance v. BP Chems., Inc., (Ohio 1996); Boudreaux v. Jefferson Island Storage & Hub, 255 F.3d 271 (5th Cir. 2001).

Hydraulic Fracturing Litigation -- Defenses to "Abnormally Dangerous" Activity Claims

This post is part of my continuing series on hydraulic fracturing litigation.  In my July 25 post, I discussed one of the legal theories that some plaintiffs are asserting -- strict liability for an "abnormally dangerous" or "ultrahazardous" activity.  Today's post discusses defenses to such claims.

In defending against an abnormally dangerous activity claim, a defendant should not assume that the doctrine applies.  Louisiana is one of the states where hydraulic fracturing is being actively used.  Although Louisiana recognizes the concept of an ultrahazardous activity, 1996 tort reform legislation limited the doctrine to just two types of activities ─ blasting with explosives and pile driving.  See Acts 1996, 1st Ex. Sess. No. 1 § 1 (amending Civil Code art. 667).

 Texas is another state where hydraulic fracturing is frequently used.  The Texas Supreme Court has suggested that Texas does not recognize the abnormally dangerous activity doctrine.  See Turner v. Big Lake Oil, 96 S.W.2d 221 (Tex. 1936).  In Turner, the defendant was storing a large quantity of produced water (salt water that sometimes is produced simultaneously with oil).  The water escaped, and flowed onto the plaintiff's land, killing vegetation and contaminating watering holes used by the plaintiff's cattle.  The plaintiff filed suit, alleging strict liability based on Rylands v. Fletcher, 3 H.L. 330 (1868).  The Texas Supreme Court rejected that claim, stating that the plaintiff would have to establish that the defendant had been negligent because Texas did not recognize the rule of Rylands v. Fletcher.  Thus, the abnormally dangerous activity theory of strict liability should be unavailable in hydraulic fracturing litigation if either Louisiana law or Texas law applies.

 Further, even in states that recognize the abnormally dangerous activity doctrine, a defendant can argue that hydraulic fracturing is not an abnormally dangerous activity.  More than one million wells have been hydraulically fractured, and there are few, if any, documented cases in which hydraulic fracturing has caused contamination of groundwater.  In addition, a defendant could present expert testimony that risks can be addressed by use of proper care in the casing and cementing of wells.  Further, hydraulic fracturing provides substantial benefits to society.  Moreover, a defendant can argue that he was not fracturing in an inappropriate place, and that instead he was fracturing right where he should ─ where geophysical evidence and prior drilling indicate a productive shale formation exists.  All these arguments can be used to assert that the factors examined by courts to determine whether an activity is abnormally dangerous weigh against hydraulic fracturing being deemed abnormally dangerous. 

 Indeed, in a case in Pennsylvania, a court denied the defendants' Federal Rule of Civil Procedure 12(b)(6) motion to dismiss an ultrahazardous activity claim, but suggested in dicta that it had doubts that plaintiffs' ultrahazardous activity claim would survive a summary judgment motion later in the case.  See Berish v. Southwestern Energy Production Co., 763 F. Supp. 2d 702, 706 (M.D. Pa. 2011).

 Even if a court deems hydraulic fracturing to be ultrahazardous, there still are defenses.  For example, § 523 recognizes that assumption of the risk is a defense.  Comment (b) to § 523 provides an example of assumption of the risk.  The comment states that, if a possessor of land, knowing the risk of blasting, consents to allow blasting on neighboring property, he cannot recover if he is harmed by the blasting.  Most oil and gas companies operate their wells pursuant to mineral leases.  If the lessor granted the lease knowing that the lessee might conduct hydraulic fracturing, and the lessor understood that fracturing allegedly has great risk, then assumption of the risk might bar the lessor's recovery.

 Further, authority exists for the proposition that strict liability does not apply if the type of harm asserted by the plaintiff is not the sort of harm that one would expect from the ultrahazardous nature of the defendant's activity.  See Restatement (Second) Torts § 519(2).  The classic example concerns blasting.  Strict liability may apply for damages caused by the explosive force of the blasting or by flying debris that results from the explosion, but strict liability would not apply if the plaintiff is a mink farmer who alleges that the blasting made his adult mink nervous, with the result that they killed their young.  See Foster v. Preston Mill Co., 268 P.2d 645 (Wash. 1954).  Thus, if a plaintiff alleged that some injury other than that which one normally would expect might be caused by the alleged hazards associated with hydraulic fracturing, strict liability might not apply. 

Contributory negligence also is a recognized defense.  See  Restatement (Second) Torts § 524.  This defense probably will not apply very often in hydraulic fracturing litigation, but it could apply in some circumstances.  For example, if a plaintiff drinks water after he suspects it is contaminated, and he later alleges he suffered personal injury from drinking the water, contributory negligence may apply.

Hydraulic Fracturing Litigation -- "Abnormally Dangerous" Activity Claims

On July 18, 2011, I made the first in a series of posts that will discuss hydraulic fracturing litigation.  I noted that plaintiffs have filed lawsuits in several states, alleging that their drinking water has been contaminated by hydraulic fracturing.  I also described the types of damages plaintiffs are alleging, and the types of relief they are seeking from courts. Finally, I listed the legal theories are "causes of action" that they typically are asserting.  One of those legal theories is sometimes described as being strict liability for harm resulting from an "abnormally dangerous" or "ultrahazardous" actvity.  Below, I provide a discussion of this legal theory, along with citations for those who desire citations to specific legal authority.

The common law has long recognized a theory of strict liability for defendants who engage in "ultrahazardous" or "abnormally dangerous" activities.  See Restatement (Second) Torts § 519.  The leading case generally is recognized as being the English case Rylands v. Fletcher, 3 H.L. 330 (1868).  In that case, the defendants were mill owners who constructed a large reservoir in which they stored water on their land.  The water broke through material used to plug an abandoned mine shaft and flooded the plaintiff's coal mine.  The lower courts held that the defendants were not negligent and that they could not be liable in the absence of negligence.  The House of Lords disagreed with the conclusion that the plaintiff had to prove negligence in order to recover, and held that a defendant can be strictly liable for an abnormal and inappropriate use of his property.

 If a particular type of activity is classified as "ultrahazardous" or "abnormally dangerous," a defendant can be held liable if he engages in that activity and thereby causes harm, even if the defendant was not negligent.  See Restatement (Second) Torts § 519.  Further, the defendant can be liable even if some intervening cause, such as the negligence of a third person or some force of nature, leads to the accident that results in harm.  See Restatement (Second) Torts § 523.

 To determine whether an activity is "abnormally dangerous," courts look to several factors.  Factors that weigh in favor of classifying an activity as abnormally dangerous include the following:  (1) the activity involves a high degree of risk; (2) any harm caused by the activity probably will be great harm, rather than minor harm; (3) it is impossible to eliminate risk associated with the activity even by the use of reasonable care; (4) the activity does not involve a matter of common usage; (5) the activity is inappropriate to the place where it is conducted; and (6) the risk of the activity outweighs value of the activity to the community.  See Restatement (Second) Torts § 520.  Classic examples of "abnormally dangerous" activity include blasting with explosives and pile driving. 

My next post in the series on hydraulic fracturing litigation will discuss defenses to "abnormally dangerous" activity claims.

Maryland Governor Announces Members of Commission to Study Shale Gas Production

Maryland Governor Martin O'Malley recently named the members of an Advisory Commission to study and make recommendations regarding shale gas production.

Maryland's Department of the Environment and Department of Natural Resources, in consultation with the Advisory Commission, will conduct a three-part study and present findings and recommendations as follows:

  • By December 31, 2011, findings and related recommendations regarding the desirability of legislation to establish revenue sources, such as a State-level severance tax, and the desirability of legislation to establish standards of liability for damages caused by gas exploration and production
  • By August 1, 2012, recommendations for best practices for all aspects of natural gas exploration and production in the Marcellus Shale in Maryland
  • By August 1, 2014, a final report with findings and recommendations relating to the impact of Marcellus Shale drilling including possible contamination of groundwater, handling and disposal of wastewater, environmental and natural resources impacts, impacts to forests and important habitats, greenhouse gas emissions, and economic impact.

The Advisory Commission was formed as a follow-up to Governor O'Malley's June 6, 2010 Executive Order establishing the Marcellus Shale Safe Drilling Initiative.  The Executive Order, together with a fact sheet issued by the Maryland Department of the Environment, stated that development of shale gas through horizontal drilling and hydraulic fracturing can have several benefits, including the generation of lease payments to individuals and government, tax revenue, jobs, and economic activity, as well as fostering both greater energy independence for the United States and the production of an energy source that is the cleanest burning of all fossil fuels.

But, stated the Governor, shale gas drilling also raises public health, environmental, and natural resources concerns, including "possible effects on drinking water."

The Marcellus Shale extends beneath Garrett County and parts of Allegheny County in Western Maryland.  The Governor's Executive Order does not place a moratorium on the issuance of permits for shale gas drilling.  The Maryland Department of Environment's fact sheet states that the Department still has authority to issue permits, and that existing Maryland law also gives the Department authority "to place all reasonable conditions in permits necessary to provide for public safety and to protect public health, the environment and natural resources." 

The Advisory Commission’s first meeting will be held at 9:30 a.m. on Thursday, August 4, 2011, in Western Maryland, at the Lakeside Visitors Center at Rocky Gap State Park and will be open to public. 

The Commission will be chaired by David Vanko, Ph.D., a geologist and current Dean of The Jess and Mildred Fisher College of Science and Mathematics at Towson University. Other members include: State Senator George Edwards; State Delegate Heather Mizeur; Garrett County Commissioner James Raley; Allegheny Commissioner William Valentine; Oakland Mayor Peggy Jamison; Shawn Bender, division manager at the Beitzel Corporation and president of the Garrett County Farm Bureau; Steven M. Bunker, director of Conservation Programs, Maryland Office of the Nature Conservancy; John Fritts, president of the Savage River Watershed Association and director of development for the Federation of American Scientists; Jeffrey Kupfer, senior advisor, Chevron Government Affairs; Dominick E. Murray, deputy secretary of the Maryland Department of Business and Economic Development; Paul Roberts, a Garrett County resident and co-owner of Deep Creek Cellars winery; Nick Weber, chair of the Mid-Atlantic Council of Trout Unlimited; and Harry Weiss, Esquire, partner at Ballard Spahr.

An article in Platts, an industry-oriented publication, expressed concern that the 14-member Advisory Commission includes only one representative from industry, while it contains three environmentalists, as well as others believed to be sympathetic to those who are opponents of hydraulic fracturing. 

West Virginia DEP to Draft Fracturing Regulations

West Virginia's acting Governor Earl Ray Tomblin has issued an Executive Order directing the West Virginia Department of Environmental Protection to use its emergency rule-making authority to draft regulations to govern hydraulic fracturing, pending the development of legislation.

Tomblin's Executive Order 4-11 mandates several requirements, including that:

  • Marcellus Shale drilling applicants seeking to drill within the boundaries of a municipality must file a public notice of intent to drill.     
  • Surface land uses that will disturb three or more acres must be certified by and constructed in accordance with plans certified by a registered professional engineer.    
  • Companies withdrawing over 210,000 gallons of water a month must file a water management plan with the DEP and adhere to certain specified standards. 
  • Before fracking begins, such companies must provide a list of additives they plan to use in the fracturing fluid, and after fracking is complete, a list of the additives actually used. 
  • When using water from a public stream, a company must identify the designated and existing uses of that stream.

Governor Tomblin's office announced the Executive Order on July 12, 2011.  In his weekly blog column, Governor Tomblin stated that use of hydraulic fracturing in development of the Marcellus Shale in West Virginia can create thousands of jobs and help recover an abundant source of energy, but that responsible environmental regulations are necessary.  It has been reported that both industry and environmental groups have reacted favorably to Governor Tomblin's Executive Order.

 Tomblin became acting Governor when his predecessor resigned to take a seat in the United States Senate.

Hydraulic Fracturing Litigation

Although there have been few, if any, documented cases in which ground water has been contaminated by hydraulic fracturing, there have been numerous anecdotal claims of contamination, and several lawsuits have been filed in which plaintiffs allege that their water has been contaminated.  Further, observers expect  many more suits will be filed. 

This blog post is the first in a series of posts that will address such issues as: what types of damages are plaintiffs alleging they have incurred; what forms of relief are plaintiffs seeking; what causes of action are plaintiffs asserting; what are the elements of those causes of action, and what defenses are applicable; what types of experts will be needed for the litigation; and where has litigation been filed, and what is the status of that litigation.  Today's post will address the types of damages being alleged by plaintiffs, the forms of relief they seek, and the causes of action they have asserted. 

Plaintiffs have filed actions in several states alleging that their ground water supplies have been contaminated.  Many of the plaintiffs assert that they have suffered physical injury from drinking contaminated water, and some claim that they now fear future medical complications.  Most assert that their alleged exposure to contaminated water makes it prudent to engage future medical monitoring for potential adverse effects.  Many of the plaintiffs assert that they cannot safely use their former water supply and that they have to obtain water from another source.  Several claim that their property has been reduced in value.  The relief most commonly sought by plaintiffs include money awards for:

  • personal injury
  • medical monitoring
  • replacement of their water supply
  • remediation or clean-up of their property or underground source of drinking water
  • loss of property value, and
  • punitive damages. 

Some of the plaintiffs have also sought injunctive relief to prohibit hydraulic fracturing. 

The causes of action most frequently alleged by plaintiffs are based on the following legal theories:

  • ultrahazardous activity
  • trespass
  • private nuisance
  • breach of contract
  • fraud
  • private attorney general or citizen suit statutes, and
  • negligence. 

In a future post, I'll discuss the nature of the causes of action asserted by plaintiffs, and some defenses that may apply. 

Louisiana Considers Mandatory Disclosure of Fracturing Water Composition

The Louisiana Department of Natural Resources ("DNR") has proposed a new regulation that would require operators to disclose information about the water used in hydraulic fracturing.  Specifically, the regulation would require operators to disclose

  • the volume of hydraulic fracturing fluid used
  • the types of additives used (for example, biocides, corrosion inhibitors, friction reducers, etc.), as well as the volume of each type
  • the trade name and supplier of each additive, and 
  • a list of the chemical compounds contained in the additives, along with the maximum concentration of each compound.

If the identity of the chemical compound is a trade secret, the operator would be excused from identifying the compound, but would be required to identify the chemical family to which the compound belongs.

The proposed rule addresses one of the recommendations made by the multi-stakeholder organization State Review of Oil and Natural Gas Environmental Regulations ("STRONGER") in a report it recently issued after evaluating Louisiana's regulation of hydraulic fracturing.  In its report, STRONGER gave Louisiana high marks, but recommending that the State implement some changes, including a requirement that operators identify the composition of fracking fluids.  DNR's Office of Conservation developed the proposed regulation, basing it in part on a mandatory disclosure regulation enacted late last year in Arkansas and a disclosure statute recently enacted in Texas. 

Louisiana's proposed regulation would require that the mandated disclosure be made either to the Office of Conservation or to FracFocus, a website operated by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission.  FracFocus posts information regarding fracturing fluid composition on a well-by-well basis, using information voluntarily submitted by operators. 

A public hearing on the proposed regulation will be held on Tuesday, August 30, 2011 in the LaSalle Building, LaBelle Hearing Room, 617 N. Third Street, Baton Rouge, Louisiana. Written comments may be submitted to Chris Sandoz of the Office of Conservation through August 12, 2011 by mail, fax, or email, and should reference "Proposed Amendment of LAC 43:XIX.118."  The contact information for submission of comments is: by mail, Office of Conservation, Engineering Division, P.O. Box 94275, Baton Rouge, Louisiana, 70804; by fax, (225) 342-2584; by email, chris.sandoz@la.gov.

There is a growing trend toward states enacting mandatory disclosure requirements.  Wyoming and Arkansas enacted such requirements in 2010 (see my 3/14/11 post).  Earlier this Summer, Texas enacted a statute requiring its regulators to develop mandatory disclosure regulations.  New York's Department of Environmental Conservation recommended such a requirement last week, and Montana also is considering such a requirement.  In addition, Michigan recently implemented a rule requiring operators to provide the state's regulators with Material Safety Data Sheets for the substances used in high volume fracturing operations (see my 6/13/11 post).

New York DEC Recommends Lifting Moratorium on Hydraulic Fracturing

The New York Department of Environmental Conservation has recommended replacing New York's complete moratorium on high-volume hydraulic fracturing with regulations that would prohibit the process in certain areas and impose several new regulations on the process in other areas.  The current moratorium was put in place last year in order to give the DEC time to supplement and revise its 2009 draft of a Generic Environmental Impact Statement ("GEIS") regarding the use of hydraulic fracturing in shale gas development.   

The 2009 GEIS had recommended allowing hydraulic fracturing throughout New York, but many officials and citizens had expressed concern about allowing hydraulic fracturing within the watersheds that supply unfiltered water to New York City and Syracuse.  Hydraulic fracturing has become an issue primarily because the Marcellus Shale extends into New York, and that shale formation contains significant quantities of natural gas that can only be recovered through the use of hydraulic fracturing.  

The DEC's new, July 2011 draft GEIS recommends regulations that would 

  • ban hydraulic fracturing in the watersheds supplying New York City and Syracuse, and within 4000 feet of those watersheds 
  • ban drilling within primary aquifers
  • ban surface drilling within state-owned parks and other lands
  • ban surface drilling within any 100-year flood plan
  • place a moratorium on drilling within 2000 feet of any public drinking water supply well until regulators can evaluate three years of experience elsewhere with hydraulic fracturing
  • require disclosure of all fracking water additives to regulators, and provide for public disclosure of all additives that do not constitute trade secrets, and
  • require an intermediate well casing (well pipe) that would be placed between the outer "surface casing" and the inner "production casing" in order to provide additional protection against migration of gas at the well itself.

The DEC's recommendations also include measures for storm water control, regulation of water withdrawals, protection of air quality at drilling sites, and for the handling of "flowback," the water recovered after a hydraulic fracturing operation is completed.

DEC officials state that they believe their recommendations provide an appropriate balance between environmental concerns and the potential benefits of hydraulic fracturing, which include jobs and a decreased dependence on foreign sources of energy.  The DEC estimates that the restrictions it recommends would result in high volume hydraulic fracturing being allowed in about 80 percent of the portion of New York into which the Marcellus Shale extends. 

The DEC made various documents available on July 1, 2011, including an Executive Summary of the revised draft GEIS.  The full revised draft of the GEIS was made available yesterday.  The documents now available include: a time line regarding the GEIS, a fact sheet regarding what DEC believes it has learned from Pennsylvania's experiences with hydraulic fracturing, a press release regarding the DEC's recommendations, a list of the members of a new Hydraulic Fracturing Advisory Panel, a PowerPoint presentation from DEC's July 1, 2011 press conference, a simple diagram showing how an intermediate casing would help protect ground water, and the full draft GEIS, which can be download in its entirety or in portions from a web page that allows downloads by individual sections of the GEIS.  A video of the DEC's July 1, 2011 press conference regarding its recommendations also is available.

DEC plans to supplement its new GEIS next month with a section discussing socioeconomic and community effects of hydraulic fracturing.  The DEC then will begin a 60-day public comment period on the GEIS.

Governor Paterson imposed the current moratorium last year in his Executive Order No. 41, in which he also ordered the DEC to revise its 2009 draft GEIS regarding shale gas development.  DEC prepared the 2009 draft GEIS in order to address the potential for natural gas drilling in the Marcellus Shale, an activity that was not contemplated at the time the DEC prepared a 1992 GEIS relating to oil and gas drilling.

Paterson imposed the moratorium at the same time that he vetoed a bill that would have banned high volume hydraulic fracturing.  The moratorium applies to fracturing operations using large volumes of fracturing fluid, such as the fracturing operations typically employed with horizontal wells, but does not apply to hydraulic fracturing that uses relatively low volumes of fracturing fluid, such as operations to hydraulically fracture vertical wells.  Governor Cuomo continued the moratorium after he took office.

Tuscaloosa Marine Shale

The Tuscaloosa Marine Shale has attracted the attention of people who work or invest in the oil and gas industry, as well as those who practice oil and gas law.  So, what is the "TSM," and why has it drawn so much interest?

The Tuscaloosa Marine Shale is a shale formation that extends in a band across the middle of Louisiana, from the State's western border with Texas, through several parishes, and on into a few counties in southeastern Mississippi.  The formation is located from 10,000 to 14,000 feet beneath the surface, and at some points is several hundred feet thick. 

One of the reasons that many people are excited about the Tuscaloosa Marine Shale is that it is a shale that contains oil.  In the last few years, shale plays that produce natural gas, such as the Haynesville, Barnett, and Marcellus, have received significant media attention, but some shale formations produce oil.  These include the Bakken in North Dakota and Montana, and the Eagle Ford in south Texas.  Prices of both natural gas and oil have dropped below levels they reached a few years ago, but the decrease in natural gas prices has been much greater.  For that reason, oil and gas companies are particularly interested in drilling in places where oil might be produced.  

This has contributed to a surge in drilling in the Bakken Shale in North Dakota.  In fact, the Baker Hughes drilling rig count shows that North Dakota is the state with the fourth largest active rig count -- behind Texas, Oklahoma, and Louisiana -- and that North Dakota has more active rigs than Louisiana if only on-shore rigs are counted.  The hunt for oil also has led to increased drilling in the Eagle Ford Shale in Texas.

The Tuscaloosa Marine Shale is a shale formation that could produce substantial quantities of oil.  A report published in 1997 by the Basin Research Institute (then part of LSU) estimated that the Tuscaloosa Marine Shale contains potential reserves of about 7 billion barrels of oil.  A recent Times Picayune article reports that such companies as Goodrich Petroleum, Devon Energy, Denbury Resources, and Indigo II Louisiana have accumulated significant lease acreage in the TSM area, and that Devon likely will be the first to drill, perhaps in East Feliciana Parish.  In years past, some wells were drilled into the TSM and produced small amounts of oil, but there are hopes that advances in hydraulic fracturing and horizontal drilling will enable companies to produce much more than in previous attempts.  In fact, Louisiana's Commissioner of Conservation Jim Welsh has been quoted as saying that the Tuscaloosa Marine Shale could be Louisiana's Eagle Ford.  

Every shale formation is different, and operators have not yet proven that the TSM will live up to the hopes many people have expressed for it, but if operators are able to produce oil profitably from the Tuscaloosa Marine Shale, it could be the site of the next big oil rush.

New Jersey legislature votes to ban hydraulic fracturing

By a lopsided margin, the New Jersey legislature has voted to ban hydraulic fracturing in the state.  The legislation, which passed by votes of 32 to 1 in the Senate and 56 to 11 in the House, would make New Jersey the first state in the U.S. to legislate a ban on the process.  Although little or no hydraulic fracturing has occurred in New Jersey, the Utica Shale lies beneath a portion of the northwestern part of the State, and companies have considered developing that resource.  The legislation now goes to Governor Chris Christie, and will become law if he signs the bill.

As previously reported in this blog, France recently became the first country to ban hydraulic fracturing.

France bans hydraulic fracturing

The French Senate has voted to outlaw hydraulic fracturing, making France the first country to enact legislation banning the process. 

Bloomberg's Tara Patel reports that the ban is comprehensive, prohibiting use of hydraulic fracturing to produce oil or gas, as well as banning all research using the process.  Companies that have existing permits for oil and gas exploration have two months to disclaim the use of fracking in France, failing which the companies' permits will be terminated.  Further, anyone conducting hydraulic fracturing within France will be subject to fines and imprisonment.

The vote in the French Senate was 176 in favor of the ban versus 151 against.  But the vote was not as close as might appear from that tally.  Much of the opposition came from the Socialist Party, whose members voted against the ban, but not because they support hydraulic fracturing.  Rather, the Socialists voted against the ban "for not going far enough." 

Given that the legislation provides for a complete ban of all fracking, as well as imprisonment of anyone who performs fracturing, it was not immediately clear how the French Senate could have gone further -- perhaps stipulating the guillotine for anyone conducting fracking, rather than mere imprisonment?  Perhaps a law banning all energy production, or a law banning all oil and gas activity, rather than just fracking?  The latter guess might be close to the mark.  One report implied that the Socialists would have preferred an outright ban on all development of shale resources, whether or not fracturing is used, though there are no indications that any companies would be interested in or capable of developing shale resources without using fracking.  France supplies very little of the oil or natural gas it consumes, and that now seems unlikely to change. 

The stock price of Toreador, a company that had been issued the most permits to explore for oil around Paris, has dropped 76 percent since January 1.  Toreador had permits for exploration of the shale resources beneath 700,000 acres of land, but those permits now may have very little value.  An analyst was quoted in another story as saying, "It doesn't look good for Toreador."

But lest anyone think that France is turning its back on modern industry, rest assured that the French still worry about the French economy, including the country's reputation for pastries and bread.  Indeed, the New York Times quoted a Parisian social worker, who expressed the following concern about the arrest of French politician Dominique Strauss-Kahn on attempted rape charges in New York: "People used to think about baguettes when they thought about France; now they think DSK." 

British Parliament issues report on hydraulic fracturing

The Energy and Climate Change Committee of the United Kingdom's House of Commons issued a report on hydraulic fracturing.  The report provides an interesting, foreign perspective on an issues that have become the subject of heated debate here in the United States.  The report includes a thorough discussion of several issues relating to hydraulic fracturing, as well as numerous specific recommendations and conclusions.  One of the Committee's conclusions is that hydraulic fracturing should be allowed to proceed in Britain:

On balance, we feel that there should not be a moratorium on the use of hydraulic fracturing in the exploitation of the UK's hydrocarbon resources, including unconventional resources such as shale gas."

The Committee analyzed both the benefits of hydraulic fracturing and the environmental concerns that have been raised.  The Committtee's report identified economic gains and decreased dependence on foreign sources of energy as being two of the benefits.  The Committee concluded that UK shale gas resources "could be considerable," though "it is unlikely that shale gas will be a 'game changer' in the UK to the same extent it has been in the U.S."  An interesting part of the report was a statement that Britain may have greater shale resources offshore than under land.

The report noted that hydraulic fracturing also has a potential environmental benefit because the process often is used to facilitate the production of natural gas, the cleanest burning of all fossil fuels ("shale gas" is simply a term for natural gas produced from shale).  The Committee stated:  "Shale gas could lead to a switch from coal to gas for electricity generation, thereby cutting carbon emissions, particularly projected emissions from developing countries." 

The report acknowledged that a countervailing concern raised by some environmentalists is that there are fugitive emissions (small leaks) of gas during the production and transport of shale gas.  Fugitive emissions are a concern because the main component of natural gas is methane, and methane (like carbon dioxide) is a greenhouse gas.  The report concluded, however, that fugitive emissions can be minimized through proper regulations.  The report also noted another concern -- that production of large quantities of shale gas might distract from efforts to develop renewable sources of energy.

But the main environmental concern that people express is a fear that hydraulic fracturing might harm the quality of underground sources of drinking water.  On this issue, the UK report reached conclusions similar to those stated previously in this blog.  The report noted that most shale formations are thousands of feet below drinking water aquifers, and that the fractures created by hydraulic fracturing are much shorter in length.  That leaves two other potential mechanisms for contamination to occur.  One would be for hydraulically-induced fractures to link with natural faults or fractures, leading to a pathway between the formation being fractured and a drinking water aquifer.  But most analysts in the United States think this is very unlikely, and the Committee seemed to agree. 

The general consensus is that, if contamination were to occur, it likely would be as a result of the other potential mechanism for contamination -- a well construction failure.  Most oil and gas wells, including both those that are hydraulically fractured and those that are not, are drilled to formations that are located deeper beneath the surface than drinking water aquifers are.  Oil or gas wells pass through the drinking water aquifer, and casing and cementing of the well are used to seal the drinking water aquifer from deeper formations.  Such casing and cementing has been done on millions of wells.  The UK report stated:

There is no evidence that the hydraulic fracturing process poses any risk to underground water aquifers provided that the well-casing is intact before the process commences.  Rather the risks of water contamination are due to issues of well integrity, and are no different than concerns encountered during the extraction of oil or gas from conventional reservoirs."

For that reason, the report concluded that care should be given to well construction standards and inspection.  The report expressed a belief that Britain's existing regulations for well construction are adequate.

Another issue of occasional concern in the United States is water supply.  Typically, a few million gallons of water are used in fracturing an oil or gas well drilled into a shale formation.  That amount is fairly modest compared to some other industrial and agricultural uses.  Nevertheless, this amount of water use can put a strain on supplies in areas that already are facing water shortages.  The UK report stated that water supply generally should not be a problem if fracturing is performed in Britain, but that fracturing "could challenge resources in regions already experiencing water stress."

The report also weighed-in on the issue of whether regulations should require that the composition of fracturing water be disclosed.  That has been a hot issue in the United States.  The UK report endorsed some reporting, but it is not clear whether the report meant to support the disclosure of the specific chemical compounds used.  The report said that well operators should report the volume of fracturing water used, as well as the "type" of chemicals used, and the concentrations.  In the debate within the United States about disclosure requirements, when people refer to the "type" of additive they often are referring to the functional category of an additive -- that is, whether the additive is a biocide, corrosion inhibitor, friction reducer, etc. -- rather than the identity of the specific chemical compound.  It is not immediately clear whether this is what the report meant, or whether it was advocating that specific chemical compounds be identified.

In addition, the report discussed the possibility of spills of fracturing fluid, and such localized effects as noise and traffic that can result from increased drilling activity, and how those concerns can be addressed.

The report contains two volumes.  The first contains the narrative report, plus a transcript of questions and answers from hearings.  The second contains written materials presented by various individuals and organizations, including environmental groups, trade groups, and companies.

EPA Selects Locations for Seven Hydraulic Fracturing Case Studies

EPA has announced locations for seven case studies regarding the potential impacts of hydraulic fracturing on underground sources of drinking water.  The locations include two sites where hydraulic fracturing has not yet started, but is planned for the near future.  These two "forward‑looking" or "prospective" sites are located in:

  • DeSoto Parish, Louisiana (Haynesville Shale)
  • Washington County, Pennsylvania (Marcellus Shale).

Five of the locations are "retrospective" study sites, where hydraulic fracturing already has occurred.  These sites include:

  • Killdeer and Dunn Counties, North Dakota (Bakken Shale)
  • Wise and Denton Counties, Texas (Barnett Shale)
  • Bradford and Susquehanna Counties, Pennsylvania (Marcellus Shale)
  • Washington County, Pennsylvania (Marcellus Shale)
  • Los Animas County, Colorado (Raton Basin, coalbed)

At the "forward‑looking" sites, the EPA will take samples and evaluate conditions through the entire life cycle of the well, beginning before the wellpad is constructed and drilling begins.  Groundwater samples from the area around each site will be analyzed for several substances, and samples of flowback water also will be analyzed.  The operator of the well at the Haynesville Shale site in DeSoto Parish, Louisiana will be Chesapeake, and work is expected to begin by this Fall.  The operator of the well at the "forward‑looking" Marcellus Shale site in Washington County, Pennsylvania will be Range Resources, and work likely will begin this Fall or sometime later.

EPA anticipates starting work at one or more of the "retrospective" sites within about four months.  For the "retrospective" study sites, the EPA has not yet defined the specific wells that will be included in the study, and therefore has not named the operators.  Samples also will be collected in the vicinity of the retrospective study sites and analyzed for various types of compounds.

The seven case study locations have different characteristics.  The Bakken Shale in North Dakota is a shale from which oil is produced.  The Raton Basin in Colorado is a site where coalbed methane has been produced.  The other five sites are locations where natural gas has been produced or will be produced from the Barnett, Haynesville, and Marcellus Shales.

The site studies are part of the EPA's previously‑announced study of the possible effects of hydraulic fracturing on underground sources of drinking water.  A preliminary report is expected in 2012, and a more detailed report in 2014.

The locations for the site studies were chosen from amongst dozens of locations suggested by various stakeholders, including public officials and the public, based on criteria in the EPA's study plan that was published in February 2012.  The EPA stated yesterday:

These criteria included proximity of population and drinking water supplies to activities, concerns about impaired water quality (retrospective only) and health and environmental impacts (retrospective only), and knowledge gaps that could be filled by the case study.  Sites were prioritized based on geographic and geologic diversity, population at risk, site status (planned, active or completed), unique geological or hydrology features, characteristics of water resources, and land use."

The EPA announced the seven sites in a statement released yesterday, and made additional information available in late afternoon, during conference calls with various stakeholders.  The EPA's study is important because it will influence public opinion on the subject of hydraulic fracturing, which has become controversial, with supporters and opponents of fracturing portraying the process in very different terms.  The EPA's study also likely will influence the views of public officials and regulators.

Michigan issues new hydraulic fracturing regulations

On May 25, 2011, Michigan's Department of Environmental Quality announced new regulations relating to "high volume" hydraulic fracturing.  The regulations will require oil and gas operators to report to DEQ the source they plan to use for water, and will require monitoring of the level in any wells within 1320 feet of an operator's proposed large volume withdrawal.  The regulations also will require operators to provide Michigan DEQ with Material Safety Data Sheets for the substances used in their fracturing.  Those MSDSs will be made available to the public.  In addition, operators will be required to provide Michigan DEQ with records relating to injection pressures, volumes of fracturing fluid, and volumes of flowback.

The new regulations define "high volume" fracturing as fracturing that uses more than 100,000 gallons of hydraulic fracturing fluid.  Michigan DEQ issued information explaining that oil and gas operators have used hydraulic fracturing in Michigan since the 1960s to produce natural gas from the Antrim Shale in the northern portion of the Michigan's Lower Peninsula.  Those wells are shallow, and typically operators only use about 50,000 gallons of water in the fracturing process.  This compares to typical water use of 4 to 5 million gallons per well in several deeper shales being hydraulically fractured in other parts of the country.  Michigan has implemented its new fracking laws in anticipation that oil and gas operators may begin drilling in Michigan to the Utica Shale, a deeper formation, and that operators would use much larger volumes of water in fracturing Utica wells than in fracturing Antrim wells.

Michigan DEQ officials have indicated that they do not believe the fracturing of underground formations itself is an issue to be concerned about, and that the important issues relate to well construction, water sourcing, and flowback disposal. 

EPA to provide webinar regarding permits for use of diesel in hydraulic fracturing

The EPA is in the process of developing guidance for the permitting of hydraulic fracturing using diesel fuel.    The EPA will hold an "Informational Public Webinar" regarding such guidance on June 15, 2011 from 2 pm to 5 pm Eastern Daylight Time (1 to 4 pm Central;  noon to 3 p.m. Mountain;  11 a.m. to 2 p.m. Pacific).  The webinar is free and open to the public, but preregistration is required, and EPA is requesting that people preregister at least 3 days in advance. 

The EPA also has posted on its website a couple of slide-presentation-type PDFs containing relevant information.  One has basic information on underground injection control.  The other document explains, among other things, that EPA's plan for developing guidance for permitting for fracking using diesel has the following timeline.  EPA will hold stakeholder meetings in the Spring, produce draft guidance by Summer, accept public comments in the Fall, and then develop final guidance.

What is this all about?

Part C of the Safe Drinking Water Act concerns protection of underground sources of drinking water.  It includes provisions for the regulation of underground injections, but the Act's definition of "underground injection" expressly excludes hydraulic fracturing operations in which diesel fuel is not part of the fracking fluid.  This has the effect of exempting hydraulic fracturing from regulation under the SDWA, provided that the fracking fluid does not contain diesel. 

Further, in the past, neither the EPA nor the States (with the exception of Alabama) have attempted to apply SDWA regulations to fracking operations that use diesel, even though those operations are not exempted from such regulations by the language of the SDWA statute.  But last year, that changed.  The EPA posted a statement on its website, stating that service companies that perform fracturing using diesel must first obtain a SDWA permit for an underground injection.  Two industry groups have brought suit, challenging the EPA's statement.  The industry groups argue that the EPA is imposing a new requirement and therefore effectively is imposing a new rule, but is doing so without going though the normal rule-making process required by the Administrative Procedures Act.  More detail about this litigation is contained in my March 7, 2011 post.

Further, because the EPA and most States have never previously regulated fracking under the SDWA, there is uncertainty about what would be required in the permitting process.  The EPA has stated it will provide guidance for such permitting.

 

Montana considers mandatory disclosure of frack water composition

Montana's Board of Oil and Gas Conservation will hold a public meeting on June 15, 2011 to consider the adoption of proposed regulations that would require operators to disclose the chemical composition of hydraulic fracturing fluids for each well fractured in Montana.  The proposed rules would allow operators to refrain from disclosing the identity of any chemicals that are trade secrets.  If, however, authorities need to know the identity of the chemicals in order to respond to a spill or release, or if health professionals need that information for diagnosis or treatment of a person exposed to the chemical, disclosure would be required.

If Montana adopts the proposed regulations, it will be following a growing trend toward the general disclosure of fracking water composition, while protecting trade secrets.  This blog has previously reported on: Wyoming and Arkansas enacting regulations last year that require complete disclosure of fracturing water composition to regulators, and provide for making all the disclosed information public, except information that qualifies for trade secret protection; Texas enacting a law last month that will lead to regulations requiring the oil and gas industry to publicly disclose fracturing water composition, except for the identity of chemicals that qualify as trade secrets; the Department of Interior considering implementing a mandatory disclosure requirement for wells fractured on federal land; and two groups of state regulators recently launching a website, FracFocus, where many operators are voluntarily disclosing fracturing water composition on a well-by-well basis.

Texas enacts frack fluid disclosure requirement

Texas has enacted legislation requiring its Railroad Commission (the regulatory authority that regulates the oil and gas industry in Texas) to develop regulations for the mandatory disclosure of the composition of water used in hydraulic fracturing on a well-by-well basis.  The new law, which is reported to be the product of negotiations involving the oil and gas industry, environmental groups, and legislators, directs that this information be posted on the internet.  Companies can request that any particular chemical be exempted from disclosure if the identity of the chemical is a trade secret.  The initial decision whether to grant an exemption will be made by the Railroad Commission, but a decision by the Railroad Commission to grant an exemption can be appealed by the landowner on whose property the well is drilled, by an adjacent landowner, or a state agency other than the Railroad Commission.

The legislation gives the Railroad Commission until July 1, 2013 to finalize regulations, but Commission members have stated that they will begin the process of developing regulations soon, and one Commissioner has said he will push to finalize regulations a year early, by July 1, 2012. 

Texas' mandatory disclosure program is significant because Texas has drilling in several shale plays -- the Barnett, the Eagle Ford, the Permian Basin, and the Haynesville (the Haynesville Shale is mostly in Louisiana, but extends into East Texas).  Further, Texas has far more ongoing drilling than any other state.  The most recent rig count by Baker Hughes shows that 843 oil and gas drilling rigs are operating in Texas.  This is nearly half of the total of 1854 rigs operating in the entire United States, and is far more than the number operating in any of the three states with the next largest totals (170 are operating in Oklahoma; 166 are operating in Louisiana; and 161 are operating in North Dakota).

When Texas' regulations are put in place, the state will join Wyoming and Arkansas in requiring disclosure.  Both Wyoming and Arkansas enacted regulations last year that require disclosure of chemicals used in fracking water on a well-by-well basis.  Wyoming and Arkansas require disclosure of all chemicals to regulators, and provide that such information generally will be made available to the public.  But the regulations in both states allow companies to request that particular chemicals whose identities constitute trade secrets be exempt from disclosure to the public.  The Wyoming and Arkansas regulations were discussed in my blog post dated March 14, 2011.

In addition to mandatory disclosure programs, two groups of state regulators -- the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission -- have organized FracFocus, a website where several companies are voluntarily posting the composition of fracking water on a well-by-well basis.  Visitors to the website can search for wells near where they live (or in any other location), or by other criteria, such as well operator.  The website also contains other information on hydraulic fracturing.  FracFocus and certain company-specific voluntary disclosure initiatives were discussed in my blog post dated April 18, 2011.

Proppants

Proppants are small particles (often sand) that are mixed with the water used in hydraulic fracturing.  The water carries the proppants into the fractures that the fracking process creates in an underground rock formation.  After the high pressure water is withdrawn, the proppants stay behind, propping open the fractures that otherwise would close upon withdrawal of the water.

An excellent article on proppants appeared in the April 2011 online version of the Journal of Petroleum Technology.  Although the Journal is published by the Society of Petroleum Engineers, you do not have to be a petroleum engineer to understand the article.  Robin Beckwith, the author, explains that there are 3 main types of proppants ─ (1) sand, (2) resin-coated proppants (usually the particles are either sand or small ceramic particles), and (3) manufactured proppants (usually these are either ceramic particles or bauxite particles). 

The article discusses the rapid growth in demand for proppants, which has led to shortages, attracting new suppliers to enter the market and prompting long-time suppliers to expand their production capacity.  Beckwith also discusses the properties that make for good proppants ─ hardness, a spherical shape, and uniformity in particle size.

Beckwith's article is well worth reading if you want to learn a little more about proppants.

Duke Study on Methane in Water Wells

Researchers from Duke University recently published a report detailing their analysis of drinking water samples from 68 water wells in the Marcellus region.  Many media sources were quick to produce sensational headlines noting that the researchers found higher methane levels in the water samples they collected within one kilometer of an active gas well, as compared to samples they collected from water wells located further than one kilometer from any active gas well.  But many of the media reports gave less attention to other parts of the study.  The report included the following notable information.

There is a lack of scientific evidence that fracking has caused contamination

The researchers stated that, despite widespread public concerns about drinking water contamination from hydraulic fracturing, such concerns "lack a strong scientific foundation."  Here, the researchers are not stating a conclusion that fracturing has never caused contamination, but they are verifying industry's contentions about the lack of scientific evidence of such contamination. 

In the wells they examined, the researchers did not find any fracking chemicals

The study found no evidence that water wells were contaminated with fracking water or produced water (produced water is water that naturally is found in the same underground formations that contain oil and gas; produced water often will contain salt and other dissolved substances that you would not want in your drinking water).  On this point, the report stated:

Based on data, we found no evidence for contamination of the shallow wells near active drilling sites from deep brines or fracturing fluids."

The researchers looked for various substances that might indicate contamination from fracking water or produced water, but found that all "concentrations from active drilling areas were consistent with the baseline historical data." 

In sum, the geochemical and isotopic features for water we measured in the shallow wells from both active and inactive areas are consistent with historical data and inconsistent with contamination from mixing Marcellus Shale formation water or saline fracturing fluids."

Methane contamination

The bulk of media attention regarding the Duke study has been devoted to the study's findings relating to methane concentrations.  For the wells they examined, the researchers found that methane concentrations generally were higher in samples from water wells located within one kilometer of an active gas well, as compared to samples from water wells located further from any active gas well.  But there were exceptions.  Further, the researchers found methane in 85 percent of the water wells they sampled, "regardless of gas industry operations."  In other words, the researchers found methane in a large majority of the water wells they sampled in the Marcellus area, even when the water wells being sampled were not located near active gas wells.

The researchers noted that water wells often contain "biogenic" methane that is formed by natural biological processes that can occur at relatively shallow depths below the earth's surface.  Through scientific analysis of the isotopes in the methane molecules found in water samples, scientists can attempt to "fingerprint" methane to determine whether it is "thermogenic" methane that comes from deep underground formations of the type from which oil and gas companies produce natural gas, or "biogenic" methane that forms naturally in shallower formations. 

Performing such analyses, the Duke researchers concluded that much of the methane they found in water samples they collected near active gas wells was thermogenic methane, rather than biogenic methane.  This result is consistent with methane contamination caused by gas drilling activity, but, for a couple of reasons, it does not prove that gas drilling caused the contamination.  The first reason is that the researchers did not have historical background data on methane concentrations or isotopic concentrations.  Thus, they could not compare pre-drilling and post-drilling concentrations for particular locations.  Second, there are ways that thermogenic methane can migrate from deep formations toward the surface.

CONCLUSION

The study's findings of higher methane concentrations and higher thermogenic methane concentrations near gas wells, though limited by the researchers' lack of "before and after" data, merit follow‑up study.  But equal attention should be given to the study's findings that the available evidence fails to show any contamination of water wells by fracking chemicals or produced water.  Further, equal attention should be given to the study's findings of high methane concentrations in a large majority of the water wells that the researchers tested, even those water wells not located near gas wells.  This indicates that the presence of methane in a water well is not enough to demonstrate that natural gas drilling caused the methane to be present.

FINAL NOTE:  In any litigation in which a landowner alleges that his water well has been contaminated with methane, a big issue to resolve will be what caused the contamination.  If the presence of methane is confirmed, the first step in the causation analysis may be the use of chemical fingerprinting to determine whether the methane is biogenic or thermogenic.  On July 7, 2011, I will be speaking as part of a three‑panelist webinar sponsored by the Defense Research Institute on hydraulic fracturing litigation.  One of the other speakers will be a chemist who will discuss the use of such chemical fingerprinting.  The third speaker will be a consultant, who is both a geologist and petroleum engineer, who will speak on topics that include well casing and cementing, the techniques that drillers use to prevent oil and gas wells from allowing leakage of gas or liquid from one underground formation to another.  Additional information on this 90‑minute program is available on the "Upcoming Speaking Engagements" button on the home page of my blog and at this link

Hydraulic fracturing -- DOE touts "Breakthrough water cleaning technology"

On April 28, the National Energy Technology Laboratory (NTEL) issued a press release regarding what it described as a "breakthrough water cleaning technology."  NTEL, which is part of the Department of Energy, described the technology as offering promise for treating both flow back water and produced water.  Flow back is the water that is used in hydraulic fracturing, then is recovered when it flows back after the fracking is complete.  Produced water is water that was present in the same reservoir as the oil and gas all along, and which is produced along with any oil or gas that is produced.

The new technology uses a nano-engineered glass structure that rapidly swells upon exposure to non‑polar liquids (such as hydrocarbons), capturing such substances.  The structure can be heated to evaporate the hydrocarbons, completely reversing the swelling process and allowing the structure to be re‑used repeatedly.

Two pilot‑scale systems have been built using the new technology.  Testing established that one of the systems removed 99 percent of oil and grease, more than 90 percent of dissolved BTEX, and "significant amounts of production chemicals."  The other system was tested on produced water from Ohio.  The system reduced total petroleum hydrocarbon levels in the water from 227 milligrams per liter to 0.1 milligrams per liter.

Both flow back and produced water can contain salts, dissolved minerals and metals, hydrocarbons (including benzene, toluene, ethylbenzene, and xylene), naturally occurring radioactive materials (NORM) present in some underground rock formations, and other substances.  In addition, flow back can contain chemical additives used to assist in the fracking process.

In some areas of the country, including Louisiana and Texas, it is common to dispose of flow back and produced water by underground injection, putting the water back into underground formations similar to those from which the produced water comes.  But in other areas, such as Pennsylvania, the geology is not as favorable for the use of injection wells and relatively few exist.  In these areas, flow back water and produced water typically are treated and then discharged into streams.  People have expressed concerns about the effectiveness of some wastewater treatment plants in removing substances found in produced water and flow back.

The technology was developed by ABSMaterial, with support from the federal government's Small Business Innovation Research Program.

Europe split on shale gas development

Europe is split on the issue of using hydraulic fracturing to develop shale gas.  Poland's turn in the rotating position of European Union President is coming up later this year.  Both Euractiv.com and EUobserver.com are reporting that Poland will use its tenure in the presidency to push the European Union to promote shale gas development.  A Polish official stated that increased shale gas development in Europe would help the EU achieve is goals for reducing emissions of carbon dioxide because natural gas is the cleanest burning fossil fuel.  Further, increased shale gas production would help decrease the EU's dependence on natural gas imports from Russia.

On the other hand, the French Parliament has begun debating legislation that would ban fracking.  According to reports, France is likely to ban hydraulic fracturing and even rescind a couple of permits that already have been granted for shale gas development via fracking.

Hydraulic fracturing studies announced

The United States Department of Energy and the University of Texas each recently announced separate plans for studies of hydraulic fracturing.

The UT study, announced yesterday, will be conducted by an interdisciplinary team led by Chip Groat, head of the U.S. Geological Society under Presidents Clinton and George W. Bush.  The team will include representatives of UT's law school, as well as the LBJ School of Public Affairs and other schools within the university.  The team will examine the effectiveness of existing laws and regulations, and will analyze claims of groundwater contamination, seismic events, and fugitive emissions allegedly related to fracking.  The team plans to complete a preliminary draft of a report by October and a final report by the end of the year.  The Environmental Defense Fund has been involved in designing the team's study, and will provide comments before a final report is issued.

The Department of Energy announced on May 5 that Energy Secretary Steven Chu has named a panel of seven people to study hydraulic fracturing.  He asked the panel to develop "immediate" recommendations to improve the safety of fracking within 90 days of the group's first meeting and further recommendations to state and federal regulatory agencies within 180 days for measures to protect the environment and public health.

The DOE panel will be chaired by John Deutch, an MIT chemist who served as a deputy secretary of defense and Director of the CIA under President Clinton.  Deutch also has served on the boards of several companies, including Raytheon, Citigroup, and Cheniere Energy, which operates a liquefied natural gas terminal and several pipelines.  Other members of the panel include:  Stephen Holditch, the head of Texas A&M's Department of Petroleum Engineering; Fred Krupp, President of the Environmental Defense Fund; Kathleen McGinty, former Secretary of the Pennsylvania Department of Environmental Protection and a former environmental adviser to Al Gore; Susan Tierney, a former Assistant Secretary of Energy for Policy under Clinton; Daniel Yergin, Chairman of IHS Cambridge Energy Research Associates and author of the Pulitzer Prize winning book, "The Prize:  The Epic Quest for Oil, Money and Power"; and Mark Zoback, Professor of Geophysics at Stanford University.

The United States Environmental Protection Agency also is sponsoring a study of hydraulic fracturing, with initial research results expected to be made public by the end of 2012, with an additional report based on further research expected in 2014.

Hydraulic Fracturing -- It's not just for gas.

Much of the news about hydraulic fracturing has concerned its use to produce natural gas from such shale plays as the Barnett, Haynesville, Fayetteville, and Marcellus.  But some shale formations contain oil, and hydraulic fracturing is playing a key role in producing oil from some of those shales, including the Bakken in North Dakota and Montana, and the Eagle Ford in south Texas.  Now, Amy Wold of The Advocate reports that Devon Energy is pursuing plans to use hydraulic fracturing to produce oil from the Tuscaloosa Marine Shale in East Feliciana Parish, not far from Baton Rouge.  A 1997 LSU study estimated that there are 7 billion barrels of oil in the shale, and Jim Welsh, Commissioner of the Louisiana Office of Conservation, is quoted as stating, "This will be Louisiana's Eagle Ford."  The use of hydraulic fracturing in shale formations already has helped the U.S. significantly increase its production of natural gas.  Now, hydraulic fracturing is starting to do the same for oil production.

Hydraulic Fracturing -- What safety issues should we discussing (part 2) ?

In my April 23 post on the recent well blowout in Pennsylvania, I suggested that the blowout should not lead to discussions about banning fracking.  Why?  Well, if a truck carrying supplies to a well was involved in a traffic accident, it would be most productive to talk about traffic safety, not about bannnig fracking.  I promised to follow-up with posts describing the safety and environmental issues that we should be discussing.  I had five issues in mind.  Yesterday, I described three of them.  Today, I'll describe the other two.

The first is the casing and cementing of wells.  Near Dimock, Pennsylvania, residents found that their water wells had high levels of methane.  They blamed Cabot Oil & Gas, which had been doing fracking in the area.  Cabot denied responsibility (and their denial had some plausibility because a large number of water wells in Pennsylvania have high concentrations of methane), but the Pennsylvania Department of Environmental Protection concluded that Cabot's operations had caused the problems.  

Pennsylvania DEP did not conclude, however, that the fracturing process itself had caused the contamination.  Instead, DEP concluded that Cabot had not properly cased and cemented the wells.  Casing and cementing are steps that provide a seal to ensure that fluids from one depth (such as a deep oil or gas formation) do not move to a different depth (such as a shallower water aquifer).  Of the millions of oil and gas wells drilled, a large fraction -- including those that are not fractured -- pass through a water aquifer on the way to a deeper oil or gas formation, and the vast majority of the time casing and cementing prevent contamination.  Our society is not about to shut-down all oil and gas drilling.  So, rather than asking whether we should ban fracking, the more useful discussion is whether cementing and casing standards are satisfactory.  

Finally, there is the issue of fracturing itself.  Industry groups state that the subterranean formations being fractured are so much deeper than the levels from which drinking water is drawn -- sometimes the formation being fracked is nearly two miles deeper than the local water aquifers -- that there is no possible way for the fractures creating by fracking to extend all the way to the depth at which drinking water is found.  Occasionally someone suggests that perhaps a fracture from the fracking will meet up with a naturally occurring fracture that goes all the way to a water aquifer, but for the most part, industry's arguments that the subterranean fracturing process itself cannot cause a problem goes unchallenged.  Indeed, a recent article in Time concluded,

The chance that fracking fluid could directly escape through the deep fractures created by the process and contaminate drinking water appears remote." 

The article suggested that spills, disposal of flowback water, and proper cementing of wells are more significant issues.  I think that's right.  And we have the know-how to deal with each of those issues. 

Hydraulic fracturing and well drilling -- What safety issues should we be discussing?

In my April 23 post on the recent well blowout in Pennsylvania, I noted that the press has predicted that the blowout will intensify the debate about fracking.  And it does appear that opponents of fracking are citing the blowout in support of their calls to ban fracking.  But, as I also stated in my April 23 post, the recent blowout, and other accidents, should lead to more nuanced discussions of safety than that.  I concluded that post with a promise that today's post would address what safety issues I think we should be discussing and thinking about.  So, here are my thoughts. 

First, blowouts can occur on virtually any oil and gas well, not just those that are hydraulically fractured (though it is worth noting that blowouts have occurred on only a very small fraction of the millions of oil and gas wells that have been drilled, whether fractured or not).  There is no way our society is going to shut-down all oil and gas drilling, so the better questions are whether this incident teaches us anything about well control and about equipment standards, and if so, what does it teach us.

Second, there have been occasions when hydraulic fracturing fluid has been spilled.  In an April 2009 incident in Louisiana, a contractor spilled fracturing fluid, which was washed into a pasture after a rain.  Seventeen cattle died.  The companies involved deny that the fluid caused the deaths, but the cattle owner believes that the cattle managed to drink some of the fluid and were killed by it. 

Such spills do not justify banning fracking.  Our society uses all sorts of hazardous chemicals, and there occasionally are spills.  We are not going to get rid of all hazardous chemicals.  The more productive discussions concern such issues as why a particular spill occurred and whether existing spill prevention, containment, and control regulations, and the enforcement of those regulations, are sufficient.  Perhaps Louisiana's regulations and enforcement are fine, and the April 2009 spill into a pasture was the result of a freak accident or the behavior of a bad actor, but maybe not. 

Third, flowback water from fracturing operations will contain whatever additives originally were in the water, plus minerals and perhaps naturally occurring radioactive material that the water absorbs from the subterranean rock formations that it encounters.  Something has to be done with this water.  Companies are starting to reuse as much of this water as they can in subsequent fracking operations, but some of the water still requires disposal.  In such states as Texas and Louisiana, most of the flowback disposal is done by underground injection, and this has created relatively little controversy.  Pennsylvania, which has different geology, has very few underground injection wells, and companies generally dispose of flowback water by sending it to wastewater treatment plants.  A recent New York Times article notes that newer treatment plants are designed to remove the types of chemicals found in flowback water, but 15 older, grandfathered facilities in Pennsylvania are not. 

But concerns about disposal of flowback water do not justify banning fracking.  A more productive question is whether there is a realistic chance that harm might result from sending flowback water to plants not designed to remove certain chemicals (some people have suggested that combining the flowback water with other water in the waste stream results in sufficient dilution to avoid any problem).  A second qustion is whether companies should start sending all flowback water to plants designed to remove all the chemicals that might be found in the water.  And to their credit, Pennsylvania officials apparently have considered these questions and answered them.  At Governor Corbett's urging, DEP recently asked companies to cease sending flowback water to the 15 grandfathered treatment plants by May 19.

In my next post, I'll discuss two final issues -- first, the casing and cementing of wells, and second, the subterranean process of hydraulic fracturing itself. 

Well blowout in Pennsylvania

On Tuesday night of this past week, an equipment failure led to a blowout at a natural gas well being drilled by Chesapeake Energy in Bradford County, Pennsylvania.  Because the blowout occurred during fracturing operations, thousands of gallons of fracking water were discharged.  The drilling site had a containment structure, and most of the fracking water was contained on the site, but some fracking water overflowed the containment structure and flowed into a creek that is a tributary of the Susquehanna River.  By Wednesday, construction crews had built a secondary containment system to prevent further flow into the creek.  Local officials stated that environmental damage appears to be minor, and it has been reported that a spokesman for the Pennsylvania Department of Environmental Protection said that a field check on Wednesday showed no effects on the Susquehanna. 

The equipment failure that lead to the blowout appears to have been a rupture at a wellhead connection.  No one was injured in the incident, and by late Thursday well control specialists Boots and Coots succeeded in temporarily plugging the well with multiple junk shots using plastic, ground-up tires, and heavy mud.  The temporary plug continues to hold, and Chesapeake is preparing to permanently plug the well.  For excellent press articles from the past few days, see accounts by Ben Casselman of The Wall Street Journal, Keiron Greenhalgh of Platts, and Edward McAllister of Reuters.

Press reports have stated that this will intensify the debate about fracking, and those reports probably are correct, but it would be much more productive if this sort of incident would prompt a more nuanced discussion of safety.  I'll provide some of my thoughts on what we should be discussing and thinking about in my next post.

Hydraulic Fracturing: Voluntary Disclosure of Fracking Water Additives

In part, the fears some people have about hydraulic fracturing are driven by lack of information about the process, including the additives used in fracking water.  Two groups of state regulators have joined efforts to create Frac Focus, a website designed to provide the public with additional information.  The website, which was launched last week, contains information about the hydrologic cycle, underground sources of drinking water, regulations designed to protect drinking water, and about how hydraulic fracturing works. 

But perhaps the most important part of Frac Focus is a portion of the website where companies can voluntarily disclose the composition of the fracking water they use for specific wells.  The disclosures are made on a well-by-well basis because companies do not always use the same composition of fracking water.  Based on their experience, and the specific circumstances relating to a particular well, companies vary the composition of the fracking water.  In the past, companies typically have kept the composition of fracking water confidential, in order to protect the competitive advantage they have gained from their experience in prior fracturing operations, but several companies have begun disclosing fracking water compositions to Frac Focus.

Visitors to Frac Focus can search for information on a well by the state and county where the well is located, by operator, or by the name and identification number of the well.  For each well, the website includes such information as: the vertical depth of the well; whether the well is an oil well or a gas well; the date hydraulic fracturing was performed; the total volume of water used in the fracturing; the concentration of each additive included in the fracking water; the purpose of the additive; the trade name and supplier of the additive; and, except for any chemicals designated as trade secrets, the scientific name and identity for each ingredient in the additive.

Some companies, including Range Resources, Chief Oil & Gas, and others already had begun disclosing similar information voluntarily, but Frac Focus will be a central source for information and will encourage additional disclosures, thereby greatly increasing the information available to the public.  Companies already have used Frac Focus to post information on a large number of wells.  The organizers of Frac Focus are the Ground Water Protection Council, an organization whose members are state regulators of water quality, and the Interstate Oil and Gas Compact Commission, a group of state regulators of the oil and gas industry.  These two groups have performed a valuable public service by organizing and launching Frac Focus.

Hydraulic fracturing: It's not just a domestic issue

My weekend reading included several articles relating to hydraulic fracturing.  Some of the most interesting articles reminded me that, in at least two ways, fracking is not just a domestic issue.  

First, although the United States currently exports a modest amount of natural gas (to Mexico via pipeline and to Aisa in the form of LNG via a port in Kenai, Alaska), the  United States is a net importer of natural gas, with most imports coming via pipeline from Canada or in liquid form (LNG) via ships from various other countries.  But with increased U.S. production of natural gas from the development of shale plays using fracking, there is growing discussion of the possibility that the U.S. might begin exporting more gas.  It has been reported that two companies -- Cheniere Energy Partners and Freeport LNG Development -- have applied to the Federal Energy Regulatory Commission for permission to export LNG.  The reason that permission would be necessary is that the Natural Gas Act of 1938 requires a person to obtain permission before exporting natural gas (see 15 U.S.C. § 717b).

Second, fracking is going on in other parts of the world, and recent articles demonstrate that people are raising the same environmental questions about fracking in places like South Africa, Canada, and Australia as some people are raising in the U.S.  But the trend abroad, as in the U.S., generally seems to be to move forward with fracking.  Further, although it is not new, readers might be interested in a neat map on the Energy Information Agency website that shows where shale formations are found around the world.

And, of course, the fracking debate still rages on here in the U.S.  The Sunday edition of the New York Times carried an article in which Ian Urbina discusses fracking, largely focusing on some of the criticisms of the process.

Hydraulic fracturing: How effective are existing state regulations?

For those concerned with how states are doing at regulating hydraulic fracturing, there is some good news.  An independent organization that includes representatives from various stakeholders, including environmental organizations, has evaluated regulatory programs in four of the states that have hydraulic fracturing activity and has concluded that those four states are doing a good job.

The non-profit organization State Review of Oil and Natural Gas Environmental Regulations ("STRONGER") was formed in 1999 to evalute state environmental regulations that govern the oil and gas industry.  Since then, STRONGER has produced numerous reports.  Recently, it has issued reports on the regulation of hydraulic fracturing in Louisiana, Pennsylvania, Ohio, and Oklahoma.  Although STRONGER's reports include suggestions to improve the regulatory programs in those  states, the reports also conclude that each of the four states already is doing a good job at regulating hydraulic fracturing.

The three-person team that studied Louisiana's regulatory program included one representative each from the Earthworks Oil and Gas Accountability Project, the Independent Petroleum Association of America, and the Oklahoma agency that regulates the oil and gas industry.  These organizations represented, respectively, three groups of stakeholders -- environmentalists, industry, and regulators.

STRONGER's report praised Louisiana's regulatory program for preventing industry's overuse of water from underground sources of drinking water.  In the early stages of developing the Haynseville Shale in northwest Louisiana, operators typically were using water from an underground drinking water aquifer to supply the water they used in fracking.  After landowners complained that water levels in the aquifer were dropping, the Louisiana Department of Natural Resources (DNR) directed operators to use surface water whenver possible to supply their fracking needs, and  the operators' use of water from the drinking water aquifer decreased dramatically. 

STRONGER also praised the Louisiana DNR for its prompt review and adjustment of regulations in response to development of the Haynesville Shale, its actions to encourage water recycling, and its public outreach and education program.  STRONGER's report suggested that Louisiana could improve its regulatory program by: adjusting its standards for casing of wells; requiring more detailed information in well reports; providing more structured training for its inspectors; and requiring wells operators to develop and implement their spill prevention and control plans earlier in the drilling process than is now required.  

The other STRONGER reports similarly contain specific praise and specific recommendations for regulatory programs in Pennsylvania, Ohio, and Oklahoma.

 

Hydraulic fracturing: What are the 3 Big Benefits?

Hydraulic fracturing and horizontal drilling are old technologies, but they have been used with increasing frequency in recent years.  With the increased use, has come publicity and a great deal of public interest.  In a prior post, I explained what hydraulic fracturing is.  What are the benefits?  The big three are

  • jobs and tax revenue
  • improved national security, and
  • environmental benefits.

One of the greatest benefits is jobs.  One of several shale formations currently being developed is the Haynesville Shale in northwestern Louisiana and east Texas.  A recent article by Mark Schleifstein of the Times Picayune reports that a Louisiana State University economist estimates that drilling in the Haynesville Shale alone generated more than 57,000 jobs in 2010.  Others states with shale drilling also have seen job growth. 

Further, a March 2010 article by AP reports that personal income of residents in 10 states has rebounded to levels higher than before the start of the recent recession.  Four of the ten are states that have significant shale drilling -- Louisiana, Arkansas, Pennsylvania, and North Dakota -- and a few of the others are states that have some shale gas drilling.

 And the economic benefits have not been limited to individuals.  Local governments have benefitted.  Bruce Nolan recently reported on the effect of Haynesville activity in DeSoto Parish, which historically has been one of Louisiana's poorest parishes (Louisiana has parishes rather than counties).  DeSoto Parish now has some of the State's highest starting salaries for public school teachers.  And, despite the recent recession that has hit most of the country, DeSoto Parish is providing new buildings to 11 of the parish's 12 schools, and paying for construction of the new buildings in cash.  Further, the parish is paying cash for an animal shelter, the parish's first public park, and a convention center.  The small town of Logansport is getting a new branch library, with construction costs to be paid in cash. 

Other states that have shale gas activity also have seen job growth.  And officials in still more states, such as Ohio, are hoping to benefit from future shale drilling, as Ryan Dezember has reported.

 Shale gas (natural gas produced from shale) also can benefit our national security.  Unrest in countries that are major suppliers of crude oil demonstrate the risk of relying on oil imports.  Drilling and hydraulic fracturing of the Bakken Shale in North Dakota and Wyoming have produced a surge of production of domestic oil.  Several other shale formations, such as the Marcellus, Barnett, Haynesville, Woodford, and Fayetteville contain enough natural gas to supply our country's energy needs for many years.  According to the Energy Information Agency, this country has potential natural gas reserves sufficent to supply the country for 110 years (at 2009 rates of consumption), and a third of that supply is found in shale formations.  Further, the estimated amount of shale gas reserves is increasing rapidly as companies continue to explore. 

 Finally, shale gas production can benefit the environment.  Of all the fossil fuels, natural gas is the cleanest burning.  A report prepared for the Department of Energy states that, for an equivalent amount of energy production, the combustion of natural gas produces only half the carbon dioxide of coal and a third less than oil.  The same report notes that combustion of natural gas also produces less particulate matter, less sulfur dioxide, and less nitrogen oxides than does the combustion of other fossil fuels. 

These are tremendous benefits.  In prior posts, I've discussed some of the concerns people have raised about hydraulic fracturing.  Those concerns should be taken seriously and should be addressed, but we should not let those concerns stop hydraulic fracturing. 

Hydraulic fracturing: What is it?

Hydraulic fracturing and horizontal drilling are old technologies, but they have been used with increasing frequency in recent years.  The increased use has come about because improvements in the technologies associated with hydraulic fracturing and horizontal drilling have made it economically feasible to produce oil and gas from shale formations, something that was not feasible in the past.  With the increased use, has come publicity and a great deal of public interest.  What is hydraulic fracturing?

First, let's take a step back.  When oil or gas is found underground, it is not located in a big, open cavern.  It is found in the pore spaces of rocks.  To produce oil or gas, a company drills to an underground formation that it hopes will contain such a product.  The target formation typically will be at high pressure (because of the weight of all the layers or rock and sediment above it).  If oil or gas is present, it will move through the rock to the well pipe, and up the well to the earth's surface.  But how does the oil or gas move through rock to get to the well?  It does so by traveling from one pore space to the next, through interconnections between the pores.

Sometimes, a formation will contain oil or gas (not all formations do), but the interconnections between pore spaces are too small in number or narrow in size for oil or gas to flow very readily through the rock.  Such formations, sometimes called "tight," have low permeability -- a measure of how easily a fluid flows through a solid.  If a formation's permeability is too low, it will not be economically feasible to produce oil or gas form the formation with conventional techniques, even if the formation contains oil or gas. 

But what if you could create additional pathways for the oil or gas to flow through the rock?  That is where fracturing comes in (also sometimes called "fracking" or "fracing").  It creates fractures or cracks in the rock, so that oil or gas can flow through the fractures, rather than just flowing from one pore space to the next.  Starting in the late 1800s, companies sometimes would engage in fracturing by lowering an explosive charge into the well and detonating it.  Such "explosive fracturing" could significantly increase production, but it also could be dangerous. 

In 1949, hydraulic fracturing was commercially developed, and since then, it has been used in over one million wells.  In hydraulic fracturing, a fluid -- typically water and various additives -- is pumped into the well at high pressure.  The high pressure fluid causes the target formation to fracture or crack.  When the high-pressure fracking fluid is removed, the fractures would tend to close.  To prevent that, the fractures are propped open with "proppants," small particles that are carried into the fractures with the fracking fluid and which remain behind when the fluid is withdrawn.  Sand is a common proppant, but sometimes small, specially-manufactured ceramic particles are used.

As noted above, water is one of the most common fracking fluids.  In addition to the proppants, various other additives are mixed in with the fracking water.  These include corrosion inhibitors to protect the well's piping, biocides to prevent microbial growth, friction reducers to reduce the friction between the fracking water and the well pipe, and viscosity adjusters to help the fracking water carry the proppants into fractures.  After a fracking job is complete, much of the fracking water is recovered, though some remains in the target formation.  

Fracking has great benefits.  As I will discuss further in a future post, fracking generates jobs and tax revenue, and it promotes our national security by decreasing our reliance on foreign sources of energy.  Fracking even has environmental benefits because it often is used to produce natural gas, the cleanest burning of all fossil fuels.  As reporters Bruce Alpert and Chris Kahn have written, President Obama has called for increased use of natural gas and increased domestic production of oil.  Fracking is a vital tool for meeting those goals.  On the other hand, people also have raised environmental concerns, primarily questions about whether water supplies could be affected.  One thing is certain -- we will continue to hear more about fracking.

Hydraulic Fracturing: Fracking additives and trade secrets

I soon will travel to Buffalo, New York, where I will serve as a panel speaker at a conference on hydraulic fracturing.  One of my co-panelists will be Professor Hannah Wiseman of Tulsa Law School.  Professor Wiseman has written some informative articles relating to water issues and hydraulic fracturing.  Her latest piece was an interesting article that recently appeared in the Columbia Law Review's online publication Sidebar.  In the article, she argues that the law should be changed to eliminate the right of companies that perform hydraulic fracturing to maintain trade secret status for the composition of the fracking they use. 

Professor Wiseman acknowledges that information regarding fracking water composition can be a valuable trade secret, that our country generally allows companies to protect trade secrets, and that good arguments exist for allowing companies to keep information about fracking water composition confidential.  She argues, however, that there are even stronger arguments for making such information public.  She asserts that increased availability of such information will serve the public interest by helping society make informed decisions about fracking. 

Taking away the right of companies to keep such information confidential certainly would be a big change in the law.  At present, virtually every state gives substantive protection to trade secrets by allowing companies to sue to protect the confidentiality of trade secrets.  Further, although both federal and state rules of civil procedure generally allow for very broad discovery during litigation, they both provide significant procedural protections by allowing courts to prevent or limit discovery of trade secrets, as well as other sensitive commercial information.  Moreover, federal and state laws that require companies to supply information to the government often provide that the government must avoid disclosing to the public the content of any trade secrets that are included in the information supplied to government. 

Ultimately, I am not convinced that we should make this big change in the law and in the right of companies to protect their trade secrets, but Professor Wiseman's article is thought-provoking.

For information on a related topic, see my prior blog post regarding new rules in Wyoming and Arkansas, and similar rules being considered elsewhere, that require companies to disclose fracking water composition to regulators (both Wyoming's and Arkansas' laws recognize that trade secrets disclosed to regulators should not then be released to the public).

Hydraulic Fracturing: Mandatory disclosure of fracking water additives

An interesting part of the debate over hydraulic fracturing has related to the proposal made by some people to require companies that perform hydraulic fracturing to disclose the composition of the fracking water they use.  Such proposals for mandatory disclosure pit two competing interests, the interest of companies in protecting their trade secrets, versus the interest of regulators and the public in obtaining more information.

The first of these interests is the interest of companies in protecting trade secrets.  Companies that perform hydraulic fracturing gain experience over time, as well as significant expertise.  That expertise has considerable value, as expertise does in any competitive business, but the expertise may be even more valuable in the fracking business than in some other fields because each fracking job is different.  Variations in geology and other factors affect how fracking should be performed.  Similarly, the composition of the fracking fluid used in fracturing operations is not a standard mix.  Each company that performs fracking uses a fracking water composition that is based on its experience and the particular circumstances of a specific fracking operation.  Fracking companies tend to treat information regarding the composition of the fracking water they use as a valuable trade secret that they strive to keep confidential.

In trying to maintain trade secrets, companies that perform fracking are no different than other companies, many of which have trade secrets or other commercial information that they seek to keep confidential.  And, our legal system respects the importance of preserving trade secrets.  At present, virtually every state gives substantive protection to trade secrets by allowing companies to sue to protect the confidentiality of trade secrets.  Further, although both federal and state rules of civil procedure generally allow for very broad discovery, they both provide significant procedural protections by allowing courts to prevent or limit discovery of trade secrets, as well as other sensitive commercial information, during litigation.  Thus, throughout the country, both substantive and procedural rules recognize that protection of trade secrets is a legitimate interest.

The opposing interest is society's interest in regulators and the public having more information about the composition of fracking water additives.  Fracking has been used on over a million wells since the process was commercially developed in the late 1940s, but the process has been used with increasing frequency as recent improvements in fracking technology and horizontal drilling have made the production of oil and gas from shale economically feasible.  With the increased use has come publicity and controversy.  Some people worry that fracking might be a threat to underground sources of drinking water, and others wonder whether drilling and environmental rules adequately regulate the process. 

 Some information about fracking water additives is publicly available.  But, because companies that perform fracking tend to keep much of that  information confidential, the information that regulators and the public have is incomplete.  If regulators had more information, that might  help them administer existing regulations and evaluate what, if any changes, should be made in existing rules.  If the public had more information, that might help the public better participate in the ongoing debate about fracking.  This has led many people to advocate mandatory disclosure of fracking water composition.

Wyoming and Arkansas are two states in which significant fracking activity occurs.  Those states enacted rules that require companies to disclose to regulators the composition of water used in fracking wells in those states.  The information disclosed to regulators will generally be made available to the public, but companies can request that trade secrets not be disclosed to the public (it was anticipated that not all information about fracking water composition would be so confidential as to rise to the level of being trade secrets).  The Wyoming Oil and Gas Conservation Commission has explained that its new regulation (Section 45 of Chapter 3 of the Oil and Gas Regulations) will allow companies to shield information from public disclosure if the information would qualify as a trade secret or as confidential commercial information under the Wyoming Public Records Act.  Rule B-19 of Arkansas' oil and gas regulations will allow companies to avert public disclosure of information that would qualify as a trade secret under 42 U.S.C. § 11042

This approach will supply some additional information to the public, while still protecting trade secrets.  And, it will require complete disclosure to regulators, who are charged with the duty of protecting the pubic interest in enforcing existing regulations and developing new rules.  There is ample precedent for such an approach.  Numerous federal and state laws require that certain types of information be supplied to the government, even if the information includes trade secrets, and that the information supplied to government generally will be made public, but that properly designated trade secrets will not be made available to the public. 

And, how have the mandatory disclosure programs in Wyoming and Arkansas worked so far?  Some people had feared that companies might make blanket assertions of trade secret status for all information they submitted, but so far that apparently has not happened.  Reports are that companies are making selective claims of trade secret status, and that regulators generally are concluding that those claims are valid. 

Other states are considering mandatory disclosure programs, and the United States Department of Interior is considering requiring disclosure of fracking water composition for wells fracked on federal land.  It well be interesting to watch whether those jurisdictions enact mandatory disclosure, and if so, how they balance competing interests.

Hydraulic fracturing: Regulation under the Safe Drinking Water Act

Can the EPA enact a new regulatory requirement merely by posting a comment on its website?  That's a question raised in litigation that companies who perform hydraulic fracturing should closely monitor. 

 Federal regulation of fracking has had a complex and interesting history.  Congress passed the Safe Drinking Water Act was enacted in 1974.  The Act required the EPA to develop minimum standards for regulatory programs that will prevent underground injections that endanger drinking water.  If the EPA determines that any particular State has developed a program for underground injection control ("UIC") that meets those minimum standards, that State may assume responsibility for administering the Safe Drinking Water Act's UIC provisions within the State, with the UIC program developed by the State becoming the SDWA UIC regulations that govern in that State.

 If the EPA later determines that the State's UIC program no longer satisfies the minimum requirements for UIC programs, the EPA may withdraw its approval, which will cause the State to lose primary enforcement authority.  The EPA then may develop and administer a UIC program for the State.  But until the EPA withdraws its approval of a State's previously-approved UIC program, that State retains primary enforcement authority and its regulations remain the law.

 For several years after the SDWA was enacted, few, if any, UIC programs regulated hydraulic fracturing or required someone to obtain a SDWA permit prior to fracking.  Both industry and the regulatory community believed that fracturing did not constitute an underground injection for purposes of the SDWA.  They believed that the SDWA UIC requirements applied to underground injections when the purpose of the injection was disposal.  Disposal is not the intent with hydraulic fracturing. 

 An environmental group challenged this interpretation in the 1990s and prevailed in a case arising out of Alabama, securing a ruling from the United States Eleventh Circuit that fracking constitutes an underground injection that must be regulated under the SDWA.  The EPA was not required to accept that decision as binding outside the Eleventh Circuit, and it apparently never did.  Alabama modified its regulations, but the EPA did not begin withdrawing its approval of other State UIC programs that did not regulate hydraulic fracturing. 

 In 1985, the Energy Policy Act amended the SDWA to provide that fracking generally will not be subject to regulation under the SDWA as an underground injection.  But the Energy Policy Act appeared to state that fracking will constitute an underground injection for purposes of the SDWA if diesel fuel is used in the fracking fluid.  This made clear that diesel-free fracking was not subject to SDWA regulation.  On the other hand, many people would argue that he Energy Policy act also made clear that fracking using should be regulated under the SDWA.  Nevertheless, most State UIC programs still did not regulate fracking at all, and the EPA still did not begin withdrawing approval of such UIC programs.

 But at some point in 2010, the EPA posted certain information regarding hydraulic fracturing on its website.  One of the pages on the website included a statement:  "Any service company that performs hydraulic fracturing using diesel fuel must receive prior authorization from the UIC program."  People in the oil and gas industry were surprised.  Perhaps the EPA and States had statutory authority under the SDWA to regulate hydraulic fracturing in which diesel fuel is used, but neither the EPA nor very many of the States had done so.  Further, because the EPA had not withdrawn its approval of any State UIC programs, those programs (along with their regulations that did not require someone to obtain a permit), industry believed that they were in compliance with the law if they were in compliance with a State's regulations.   do so.

 The Independent Petroleum Association of America and the U.S. Oil & Gas Association have responded by filing suit, challenging statement on the EPA's website as an attempt to regulate by making a web posting, rather than following the rule-making process established by the Administrative Procedures Act.  The EPA is seeking to dismiss the challenge, arguing that the agency did not enact a new regulation, and that it merely posted information on its website about existing regulatory requirements. 

 The IPAA has noted in a memorandum to the court that, in 2005, the EPA informed Congress that, "current federal UIC regulations do not expressly address or prohibit the use of diesel fuel in fracturing fluids."  The IPAA also noted that the EPA has not withdrawn its approval of any State UIC programs, even though most of those programs do not regulate fracking, even if diesel fuel is used in the fracking fluid.     

 The IPAA appears to have sound arguments, but if the court accepts the agency's argument that the EPA merely was posting information about existing regulatory requirements, the court likely will reject the IPAA's challenge.  The resolution of this litigation will have significant implications for the regulation of hydraulic fracturing operations that use diesel fuel, as well for such questions as what constitutes creation of a new regulatory requirement and when citizens can challenge an EPA action.

 Companies that perform fracking should watch this case closely, particularly if they sometimes have been performing fracking in which diesel is used.  Further, such companies probably should proceed carefully and consider consulting their attorney before they conduct future fracking operations using diesel.  The litigation is Independent Petroleum Association of America v. United States Environmental Protection Agency, No. 10-1233, currently pending in the D.C. Circuit.