Illinois Governor Signs Fracking Legislation

This post was written by Edward Walsh

Claiming that the legislation will give the state the strongest environmental standards for hydraulic fracturing operations, or “fracking” in the United States, on June 17, Illinois Gov. Pat Quinn signed into law a bill regulating the practice. The Hydraulic Fracturing Regulatory Act introduces the first comprehensive controls on fracking in the state. Among other things, it requires oil and gas drillers to disclose which chemicals they are using both before and after fracking operations and requires water sampling of pre- and post-fracking groundwater with operators liable for any ensuing water pollution. The New Albany shale formation in southern Illinois, believed to contain billions of cubic feet of natural gas, is the focal point of the now settled fracking debate in Illinois.

The law will be implemented by the Illinois Environmental Protection Agency and Department of Natural Resources. Applications for fracking operations are now subject to public comment periods and a public hearing. Once approved, operators must submit both pre- and post-fracking chemical disclosures to the state, in contrast to the practice in other states. Operators may attempt to shield the identity of the chemicals they use from public disclosure under “trade secret” provisions with such claims subject to challenge through the state’s freedom of information law.

In contrast to standard practice, wastewater from operations must be stored in above-ground closed tanks, rather than in pits typically used in the industry. Operators must test groundwater around the fracking area against a predrilling baseline, 6, 18 and 30 months after operations commence. Operators are responsible for groundwater impacts if testing shows that the baseline standard has been exceeded, absent convincing evidence that their fracking operation was not the source of the impact.

The law has the support both industry groups and environmental groups making legal challenges unlikely.

Pennsylvania Issues New General Permit for Oil and Gas Wastewaters

This post was written by Mark Mustian

On March 24, the Pennsylvania Department of Environmental Protection (DEP) revised and reissued General Permit WMGR123, which authorizes the processing and beneficial use of processed liquid wastes generated on oil and gas well sites and associated infrastructure. WMGR123, issued under the authority of the Bureau of Waste Management, replaces the three existing general permits which previously regulated the recycling and reuse of oil and gas wastewaters.

Wastewater generated from well sites that is sent off-site for reuse is regulated as a residual waste, and requires permitting by DEP's Solid Waste Group. Prior to the issuance of the new general permit, there were 3 different general permits applicable to oil and gas operations: WMGR119, WMGR121, and WMGR123. The required permit was based upon the source of the water, the type of treatment, and the use of the recycled water, but the permits were generally very similar. WMGR119 and 121 are now revoked and all off-site activities will be authorized under the new WMGR123 permit. In addition, the on-site reuse of drilling wastes has previously been authorized by the Oil and Gas Program through submittal of Form 5500-PM-OG0071. There is no indication that this procedure has changed, but it is a question that will need to be answered.

The new general permit removes some current restrictions on the recycling of oil and gas wastewaters, and also adds some new requirements. For facilities that plan to recycle and reuse relatively dilute waters, the new permit should be helpful. In particular, for wastewaters with low total dissolved solids (TDS) (i.e., less than 500 mg/l) that are in compliance with standards found in Appendix A of the permit, the operator will not have to manage the waste as a residual waste, and should be able to utilize existing designs for impoundments and handling of the water. This approach would work for water generated at a well site and stored prior to transport to a recycling facility, and for recycled water which has been treated and transported to a well site for reuse. These wastewaters with low TDS will no longer have to be transported as a residual waste.

However, for high TDS wastewater which does not comply with the Appendix A standards, both the generators and users of the recycled water will potentially have new compliance standards. Until the processed oil and gas liquid waste has been transported to a well site and is actually used to develop a well, it must be managed as a residual waste. From the language of the permit, it appears that the requirement to manage the wastewater as a residual waste would apply to both the operator generating the waste and the operator reusing the waste. This will require the operators at both sites to comply with the regulations on storage and transportation found at 25 Pa Code § 299, and in particular the permitting and design requirements for impoundments found in Section 299.141 through 299.145. If either the generator of the waste, or the party beneficially reusing the waste wishes to store the waste prior to either shipment or reuse, they will need to comply with storage requirements that are generally more stringent than the requirements under the oil and gas regulations.

Moreover, the permit holder must comply with several other requirements associated with the general permit. They include: a bonding requirement; sampling requirements to determine whether the wastewaters comply with the Appendix A standards; facility siting requirements; and inspection and records requirements. Overall, the new general permit appears to be designed for permanent recycling facilities that are receiving water from various drill sites, processing it, and then sending it out for reuse at other sites. It does not appear that the general permit will work effectively for individual well sites that want to just transport their water to another well site for reuse.

Key Environmental and Safety Provisions in New Pennsylvania Gas Act

This post was written by Jennifer Smokelin

On February 14, 2012, Pennsylvania Governor Corbett signed House Bill 1950 into law as Act 13 of 2012, the Unconventional Gas Well Impact Fee Act (Act 13). This long bill (174 pages) provides for an impact fee, Oil and Gas Act (Title 58) amendments and local ordinance standards. We followed the legislative progression of the Act and, as promised, offer more detailed analysis of the environmental aspects of the Act here. In short, Act 13 provides for new well fees to be assessed on unconventional wells as well as restrictions on local government’s authority to impose burdens on oil and gas activities over and above those required by the state (which some municipalities are preparing to challenge). There are also new environmental and safety provisions for both surface and subsurface activities, some of which will be effective immediately while other will require a rulemaking by the Environmental Quality Board before becoming effective. This article discusses five significant “specifics” of the new environmental and safety provisions imposed by Act 13 and the implications on future permitting and operation of unconventional natural gas development.


  1. The Act provides enhanced hydraulic fracturing chemical disclosure requirements – this is a new requirement.

Act 13 requires operators of unconventional wells to disclose hydraulic fracture fluids to the Chemical Disclosure Registry (which is a website developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission) which will make information about chemicals and additives available to the public in a fully searchable format. Act 13 provides, “Within 60 days following the conclusion of hydraulic fracturing, the operator of the well shall complete the chemical disclosure registry form and post the form on the chemical disclosure registry in accordance with regulations promulgated under this chapter in a format that does not link chemicals to their respective hydraulic fracturing additive” (section 3221.1) Specific information regarding chemicals claimed as trade secrets and proprietary information can be protected from disclosure. Further, certain “trace amounts” of chemicals need not be disclosed.

Act 13 also provides for enhanced well reporting requirements, including production data.

The implication of this provision on future operation of unconventional natural gas development is clearly to require operators to know and disclose hydraulic fracking fluids, even if those chemicals are being supplied by a vendor. Further, it is intended that the Registry be “fully searchable” by the Pennsylvania Department of Environmental Protection (DEP) and the public by geographic region on state wide bases. This could have liability implications in penalty and alleged contamination cases.

  1. Producers must submit to DEP a report identifying and quantifying actual air contaminant emissions, with the report due by March 1 for air contaminant emissions during the preceding calendar year – this is a new requirement.

Section 3227 of Act 13 requires an owner or operator of a facility conducting natural gas operations in unconventional formations including development, production, transmission and processing to “submit to the [DEP] a source report identifying and quantifying actual air contaminant emissions from any air contamination source.” The reports under this section are due March 1 for the preceding year. Previously, on December 6, 2011, DEP alerted companies involved in unconventional natural gas development around Pennsylvania that they must submit to the department data on their facilities’ air emissions for 2011. The reports are due March 1, 2012. Details regarding the air emission inventory can be found here. It is unclear at this time whether and to what extent Act 13 changes or modifies the emission reporting requirements DEP notified regulated entities about in 2011.

  1. Increased record keeping for transportation of waste water fluids – this is a revised requirement.

Under Act 13, producers are now required to maintain transportation records regarding the movement of wastewater In many ways, this is yet another move on the part of the legislature and DEP to discourage disposal of fracking wastewater and encourage on-site reuse. DEP’s preference for onsite reuse can also be seen in another provision of Act 13 where DEP can now deny permits for “failure to submit a water management plan that does not include a reuse plan for fluids that will be used to hydraulically fracture a well.” Therefore, the implication of these provisions on future operations of unconventional natural gas development is to look for future policies to further encourage reuse of wastewater.

  1. Unconventional operators are presumed to be responsible for pollution of water supplies within 2,500 feet of the well bore when the pollution occurs within 12 months of the later of completion, drilling, stimulation or alteration of the well – this is a revised provision.

The Oil and Gas Act has always contained a rebuttable presumption of liability for pollution from gas wells. This rebuttable presumption was based on the distance of the well pad from the alleged pollution and the timing of the pollution event. Act 13 increases the distance of the rebuttal presumption of pollution from 1,000 feet to 2,500 feet from the water supply and the timing of such presumption is increased from six months to 12 months following the last drilling activity for unconventional drilling. The implication on future operation of unconventional natural gas development is an increase in an unconventional well operator’s window of presumed liability, both in distance and time.

  1. Additional permitting and penalty provisions – this is a revised provision.

There are many permitting and penalty provisions in Act 13, including newly required notices to municipalities, as well as water management plans. Further, the Environmental Quality Board must issue regulations for DEP to use in evaluating: impact to public resources, for “ensuring optimal development of oil and gas resources” and respecting property rights of oil and gas owners. Further, aligning itself with other PA environmental statutes, the Oil and Gas Act now explicitly states that permits may be denied for continuing violations by an applicant’s parent or subsidiary. Also, Act 13 increases threefold the “not to exceed” ceiling for civil penalty assessment against unconventional well operators, and it is now up to $75,000. The implications on future permitting operations of unconventional natural gas development could be significant, and the EQB regulations will be something to watch for.

 . . .

There are many other changes to the Oil and Gas Act under Act 13: bonding requirements, well siting and set-back provision changes, and well control emergency response - to name a few. This article serves to highlight five of the more significant measures. If you have questions with regard to other proposed changes (or the Act 13 changes listed here) please contact us. 

U.S. Shale Gas in 2012: Top 10 Environmental Legal Issues to Watch

This post was written by David Wagner and Jennifer Smokelin.

This article was published in Rigzone on February 16, 2012.

In his State of the Union address in late January, President Obama offered his support to further develop natural gas as an energy source and stated that “my administration will take every possible action to safely develop this energy.” The president also underscored that this development requires environmental safeguards. He added: “I'm requiring all companies that drill for gas on public lands to disclose the chemicals they use. America will develop this resource without putting the health and safety of our citizens at risk.” In this context, what can we expect from environmental regulators this year? In our outlook for 2012, we identify 10 environmental legal issues to watch.

1. U.S. Environmental Protection Agency’s First Report on the Impact of Hydraulic Fracturing on Drinking Water Resources

The U.S. Environmental Protection Agency (EPA) is studying the impacts of hydraulic fracturing on drinking water resources primarily in shale formations. Look for EPA’s initial study results this year and an additional report based on long-term study projects in 2014.

The results will no doubt be an impetus for regulatory and policy changes that could have a significant impact on the shale gas industry. Hydraulic fracturing involves injecting water, sand and chemicals deep underground to break up shale rock formations that contain natural gas. Under the study, EPA researchers, in collaboration with outside experts from the public and private sector, will examine the impacts of: large volume water withdrawals from ground and surface waters; surface spills resulting from hydraulic fracturing fluids; the injection and fracturing process; surface spills of flowback and produced water; and wastewater treatment and waste disposal.

2. EPA’s Development of Hydraulic Fracturing Wastewater Standards

EPA is also developing national standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The federal Clean Water Act (CWA) effluent guidelines program sets national standards for industrial wastewater discharges based on best available technologies that are economically achievable. Effluent guidelines for oil and gas extraction prohibit the on-site direct discharge of wastewater from shale gas extraction into waters of the United States. While some of the wastewater from shale gas extraction is reused or re-injected, the rest still requires disposal. Currently, the disposal of wastewater generated by shale gas production activities is regulated by the states. In some states, wastewater is injected into deep underground shafts, while in others, wastewater has been sent to sewage treatment plants.

In 2012, EPA plans to gather data, consult with stakeholders – including industry stakeholders – and solicit public comment on a proposed rule for wastewater discharges produced by natural gas extraction from coalbed methane in 2013, and a proposed rule for shale gas in 2014. The schedule for coalbed methane is shorter because EPA has already gathered data in this area. In particular, EPA will be looking at the potential for cost-effective steps for pretreatment of wastewater based on practices and technologies that are already available and being deployed or tested by industry to reduce pollutants in these discharges.

3. EPA’s Permitting Guidance on Underground Injection Control for Facilities that Use Diesel Fuels in Injection Fluids

The Safe Drinking Water Act’s (SDWA) Underground Injection Control (UIC) program establishes requirements for proper well siting, construction, and operation to minimize risks to underground sources of drinking water. Even though the Energy Policy Act of 2005 excluded hydraulic fracturing for oil and gas production from permitting under the UIC Program, the exclusion did not include fracturing using diesel fuel. Armed with the authority to regulate hydraulic fracturing using diesel fuel, EPA is developingpermitting guidance for fracturing activities that use diesel fuels in fracturing fluids. The permitting guidance is expected this year and EPA has indicated that it will include a broad definition of diesel fuel, e.g., a definition that includes substances with physical and chemical characteristics of diesel such as BTEX compounds (benzene, toluene, ethyl benzene and xylene).

4. EPA to Start Rulemaking Process on the Disclosure of Chemicals Used in Hydraulic Fracturing

In November 2011, EPA stated that it will begin a rulemaking procedure under the Toxic Substances Control Act (TSCA) to require companies to disclose information on the chemicals used in hydraulic fracturing. In a response to a petition filed by Earthjustice and 120 other organizations, EPA stated that it “believe[s] there is value in initiating a proposed rulemaking process using TSCA authorities to obtain data on chemical substances and mixtures used in hydraulic fracturing.” EPA has not stated what information will be subject to disclosure, but has limited disclosure to substances used in hydraulic fracturing. EPA said it will attempt to avoid duplication of “the well-by-well disclosure programs already being implemented in several states,” and its regulations will “focus on providing aggregate pictures of the chemical substances and mixtures used in hydraulic fracturing.” In 2012, EPA is expected to issue an advanced notice of proposed rulemaking followed by a stakeholder process and public comment period.

5. U.S. Department of the Interior’s Proposed Regulations Related to Hydraulic Fracturing on Public Lands

For shale gas production on public lands, the U.S. Department of the Interior is drafting a regulation on hydraulic fracturing disclosure requirements for companies drilling there. In late January, Interior Secretary Kenneth Salazar said that more information on the proposed rule would be forthcoming in the next several weeks. In addition to chemical disclosure provisions, the rules are expected to address wellbore integrity following hydraulic fracturing and the management of wastewater.


6. Increased Discussion and Proposed Legislation on a “Clean Energy Standard” that Includes Natural Gas

Despite the challenges of passing legislation in an election year, look for more discussion on a “clean energy standard” in the U.S. Congress and proposed legislation on the matter. Senate Energy and Natural Resources Committee Chairman Jeff Bingaman (D-N.M.) has said he will introduce a clean energy standard (CES) early this year.

Under a national CES, all electricity supply companies would have to produce a certain percentage of their electricity from clean energy sources, purchase a like amount of credits, or a combination of both. In 2011, a proposal from the Obama administration included efficient natural gas (i.e., combined cycle) as a clean energy source and it was awarded “half credits” under the president’s proposal. In developing a CES, Sen. Bingaman has to address many design questions that require careful consideration. And the decisions made in the design of such a standard will necessarily favor certain priorities over others. As you might expect, discussion and debate on a clean energy standard will focus on, among other issues, effectiveness, fairness, and the likelihood of bipartisan support.

7. EPA Final Rule Related to Air Emissions from the Oil and Natural Gas Sector

Turning to air emissions, EPA is expected to promulgate final rules under the Clean Air Act on emissions from oil and natural gas exploration, production, transmission, and storage facilities by April 3, 2012. The rules will broaden EPA’s regulation of oil or gas production to reach most operations associated with production activities and address both new and existing sources. In particular, the rules are likely to include a New Source Performance Standard that will regulate volatile organic compound and sulfur dioxide emissions from non-combustion sources in the oil and gas industry, and in midstream natural gas industry. The rules are also expected to amend and expand two existing National Emissions Standards for Hazardous Air Pollutants that regulate emissions of air toxics from these industry sectors for both new and existing sources. As proposed, the new rules will regulate emissions from several types of emission sources that have never before been subject to federal standards, including hydraulic fracturing operations, gas-driven pneumatic devices, centrifugal and reciprocating compressors, condensate and crude oil storage tanks, and small glycol dehydrators.

8. Aggregation of Air Emissions

At least five pending litigation actions address the scope and application of aggregation. Aggregation is the process of determining whether emissions from multiple operations should be combined (or aggregated) into a single source for air permitting purposes. If emissions from individual operations such as wells, processing plants and compressor stations are combined, they could constitute a “major stationary source” or a “major facility” for purposes of the Prevention of Significant Deterioration, New Source Review and Title V permitting programs under the Clean Air Act. The aggregation concept derives in part from EPA’s definition of “stationary source,” which means any building, structure, facility, or installation that emits or may emit a regulated pollutant.” Moreover, a “building,” “structure,” “facility,” or “installation” is defined as all the pollutant-emitting activities that: (1) belong to the same industrial grouping; (2) are located on one or more contiguous or adjacent properties; and (3) are under the control of the same person. Typically, the “adjacent” analysis is at the core of an aggregation determination.

This definition, especially as it relates to “adjacent,” is likely to be applied differently in some of the litigation cases, and the case outcomes should be looked at closely in 2012. For example, two of the cases are in Pennsylvania (which is in EPA’s Region 3): Clean Air Council v. DEP (EHB Docket No 2011-072-R), pending before the state’s Environmental Hearing Board; and Citizens for the Future of Pennsylvania v. Ultra Resources, 4:11-cv-01360-JEJ, pending in the U.S. District Court for the Middle District of Pennsylvania. These two cases will presumably be decided under the Pennsylvania Department of Environmental Protection’s new “Guidance for Performing Single Source Determination for Oil and Gas Industry,” which was effective October 12, 2011. In the guidance, the state regulators indicated that, when considering the “adjacent” analysis, they will not consider the interrelatedness of operations. This interpretation contrasts with the interpretation supported by EPA in Summit Petroleum Corporation v. EPA (Case No. 09-4348). In the Summit Petroleum case, pending before the federal Sixth Circuit Court of Appeals (and in EPA’s Region 5), EPA has argued that, in considering the “adjacent” analysis, the test for operations should be “functional interdependence.”

With cases in different EPA regions and the potential for different interpretations, it is likely that, following any court decision, EPA will attempt to resolve conflicting standards.

9. Private Lawsuits Alleging Personal Injury and Property Damage from Hydraulic Fracturing

Environmental tort liability under federal and state laws provides legal rights including nuisance, trespass, negligence, strict liability, restitution and waste. Compensation may be available for property damage, bodily injury, emotional distress, medical expenses, loss of profits, and punitive and injunctive relief. In 2012, these legal theories will be tested as to their applicability to damages alleged from hydraulic fracturing. On this issue, plaintiffs’ lawyers are already investigating property damage claims and trying to connect the proximity of residents to drilling operations with increased disease diagnosis (e.g., leukemia). Look for more filings of these types of cases.

While private litigation increases liability exposure for drillers, there are possible ways to mitigate the risk. For example, one type of potential action relates to strict liability (or near strict liability) provisions. In Pennsylvania, the state’s Oil and Gas Act establishes baseline protections against the contamination of public and private water supplies. Under the law, a well operator is presumed “to be responsible for the pollution of a water supply that is within 1,000 feet of the oil or gas well, where the pollution occurred within six months after the completion of the drilling or alteration of such well.” This law shifts the burden of proof to the well operator to show that the pollution was pre-existing, from a source other than drilling operations, or outside of the time and distance parameters in the statute. If the landowner or water rights owner believes that it has suffered contamination, it could file a complaint with the state. If a subsequent state investigation indicates the well operator has polluted the water supply, the well operator must restore or replace the water supply. To reduce liability exposure and preserve the pre-existing pollution defense, well operators should conduct a pre-drilling survey of the water assessment against EPA water quality criteria.

10. State Efforts to Impose Moratoriums

Although moratoriums on hydraulic fracturing are frequently discussed in the press, the hoopla seems to grow out of the threat of a moratorium. Only one state, New York, has actuallypassed a moratorium, and it is a temporary ban pending review of regulations. New York placed a moratorium on drilling permits in 2008 and has spent the past three years reviewing its regulations. Most recently, a public comment period on the review of impacts from fracturing and proposed regulations closed January 11, 2012.

Some of the proposed moratoriums in other states include:

  • Vermont, where a bill imposing a three-year moratorium on hydraulic fracturing is working its way through the legislature
  • Ohio, where proposed legislation would establish a moratorium on horizontal stimulation of oil and gas wells until EPA publishes a report containing the results of a study of the relationship of hydraulic fracturing to drinking water resources, and the state issues a related report
  • Michigan, where several bills would impose a two-year moratorium on the issuance of any new permits for hydraulic fracturing until EPA and the state are able to study its effects

This year, we can expect to see more political discussion on these issues, which may result in delaying some drilling efforts. However, for a few reasons, a permanent moratorium in any state is unlikely. EPA has assured states it will not issue a moratorium on hydraulic fracturing. Also, keep in mind that legislatures (and, based on the State of the Union address, the Obama administration) are not opposed to developing these energy resources. Rather, as the president said, the issue is developing “this resource without putting the health and safety of our citizens at risk.” Stay tuned.