Recent enhanced drilling techniques have made it economically feasible to drill wells in certain shale formations, like the Marcellus Shale, and tap into the estimated trillions of cubic feet of natural gas trapped within those formations. This has resulted in numerous M&A transactions involving companies in the shale gas exploration and production (E&P) business as well as those related businesses that support or benefit from shale gas E&P. PE firms too have been looking at the possibility of investing in companies in shale related activities. According to a report by PricewaterhouseCoopers, “merger and acquisition activity in the shale arena has been booming since 2008, and much of it consists of foreign investors, international oil companies and even some national oil companies partnering with U.S. independents in joint ventures.”2 Given the importance of natural gas development to the U.S. economy and environment, it is reasonable to expect that the level of transaction activity in this sector will continue to grow at a brisk pace.

M&A transactions in the shale gas E&P sector have been, and will continue to be, completed against a backdrop of changing regulatory requirements for some time to come. The recent and rapid expansion of Marcellus Shale gas E&P activities has left many regulators struggling to catch up. A quickly changing regulatory regime can affect the timing and size of the expected rate of return on an investment and/or increase the environmental risks in an investment or financing. The jurisdiction in which a target’s natural gas assets are located as well as the stage of the target’s natural gas E&P also could have an effect on deal risk. Consequently, environmental due diligence of proposed M&A transactions in the “up-stream” shale gas E&P sector should include not only the environmental profile and compliance status of the target but also an evaluation of the environmental regulatory regime in the relevant jurisdictions — both in effect and proposed. The purpose of this article is to offer suggestions for specific environmental due diligence inquiries in light of the current and changing regulatory regime.

The Marcellus Shale and “Fracking”

The Marcellus Shale is located principally beneath parts of New York, Ohio, Pennsylvania, and West Virginia. It ranges in depth from 4,000 feet to 8,500 feet below the ground surface (bgs). The advent of enhanced drilling techniques, such as horizontal drilling and hydraulic fracturing (fracking or fracing), has made it possible and economically feasible to extract natural gas from the Marcellus Shale. Fracking stimulates gas extraction by pumping a fluid and a “proppant” — such as sand — down a well under high pressure to fracture the gas-bearing rock formation. The proppant keeps the fractures open so more gas can be extracted. Fracking fluid typically consists of more than 98% water and sand, with less than 2% chemical additives that may include friction reducers, biocides, gels to carry the proppant into the fractures, solvents, surfactants and other additives. Marcellus Shale wells each use between 3.0 million and 5.0 million gallons of water. Approximately 15 percent of the fracking fluid injected into shale gas wells returns to the surface as so-called “flowback” water.

The Environmental Issues Raised in the Fracking Discussion

The primary environmental debates regarding fracking address whether: (1) the released natural gas can migrate out of the wells and impact the environment; (2) the fracking fluid can escape and impact the environment during injection; (3) improperly designed or installed wells will result in releases of natural gas or fracking fluid; and (4) the fracking fluid and flowback water can be stored and disposed of in an environmentally sound manner.

Views diverge over whether creating fractures in the Marcellus Shale itself presents an unreasonable risk of impacting water resources. Because the Marcellus Shale is located 4,000 to 8,500 feet bgs and groundwater is located approximately 600 feet or less bgs, however, it seems unlikely the hydraulic fracturing process could result in contamination of drinking water resources. Nevertheless, improperly designed or installed well casings and surficial releases of waste flowback water prior to injection or treatment have been alleged to result in impacts to surface and groundwater. As with conventional gas wells, there also have been allegations that defectively designed or installed fracking wells can result in blow-outs.

Waste flowback water can contain relatively high concentrations of total dissolved solids (TDS); naturally occurring radioactive material; and volatile organic compounds (VOCs). During the return of flowback water to the surface, methane, other VOCs, and toxics in the flowback can be released to the atmosphere unless controlled. Approximately 60% of flowback water is recycled. The primary means of disposal of waste flowback water that is not recycled are: (i) deep injection back into the ground and (ii) transportation to potentially remote storage and treatment locations by pipeline or truck, after which it is discharged to surface water. Deep injection of waste flowback water has been alleged to be a potential cause of earthquakes. The second disposal option also raises environmental questions. The typical publicly owned treatment works (POTW) can only treat TDS and radioactivity through dilution, and inadequate treatment of waste flowback water has been identified by the U.S. Environmental Protection Agency (EPA) as a potential cause of surface water contamination.

Fracking wells emit methane gas and other VOCs into the atmosphere. More generally, shale gas E&P can result in increased industrial activity, trucking, and general construction activities, prompting discussion of potential community impacts. The President’s FY 2013 budget includes $14 million for research on the effect of hydraulic fracturing on air quality, water quality, and ecosystems.

Recent Legislative and Regulatory Developments

The rapid expansion of natural gas E&P in the Marcellus Shale has created a rapidly changing legislative and regulatory environment. A great deal of attention has been focused on the public disclosure of chemical additives used in fracking. Currently, federal law requires disclosure of fracking fluid additives (and underground injection well permits) only where diesel fuel is used in the fracking fluid. Proposed Department of Interior regulations would impose a disclosure obligation on wells drilled on federal and Indian lands. Some states also require fracking fluid additive disclosure.

In addition to disclosure, the federal government has recently initiated regulatory activity addressing perceived risks to surface water, drinking water and air. In 2011, EPA announced its intent to develop regulations governing pre-treatment of flowback water before discharge to wastewater treatment plants. Those regulations will likely require some form of evaporation/distillation to meet the current federal drinking water standard for TDS at an estimated cost of $0.25 per gallon.3 EPA also is currently studying the potential impact of hydraulic fracturing on drinking water supplies. It proposes to issue initial study results in 2012 and final results in 2014. It was only on April 17, 2012 that the EPA published new regulations governing air emissions from fracking wells. The new rules require reductions in VOCs from completions of new gas wells and recompletions of existing gas wells that are fractured or refractured. EPA would minimize the VOC emissions by requiring the use of “green completion” technology at an estimated cost of $34,000 per well per completion.

State governments and regional compact authorities (e.g., the Susquehanna River Basin Commission) are also actively involved in regulating fracking. Fracking bans or moratoria, at least in the short term, exist in certain states and regions (e.g. New York and the Delaware River Basin) while they actively evaluate the perceived risks of fracking and how best to mitigate such risks. State and regional compact regulations governing Marcellus Shale fracking vary in their approaches to where fracking may occur and what operational requirements for well installation and fracking are required. In addition, state fee payments have begun to increase. For example, Pennsylvania recently enacted legislation imposing a per-well fracking “impact fee,” which varies based on a formula tied to annual average natural gas prices.

Increased federal, state and regional regulation of fracking will increase the time and cost to obtain permits and site, construct and operate new wells. The relative differences between state and regional approaches to fracking regulation also can have a significant effect on the value of, or the time to recover on, an investment in a given geographical area.

Environmental Due Diligence for Transactions Focusing on Marcellus Shale Fracking

In evaluating environmental regulatory risks associated with transactions involving upstream Marcellus Shale gas E&P companies, consider including some or all of the following questions in your environmental due diligence review:4

  1. What is the environmental risk profile of the target:
    1. Is the target the subject of any pending environmental regulatory compliance investigation or other administrative proceeding? Any pending or threatened environmental claims or litigation?
    2. Does the target have a history of well blowouts or issues associated with alleged poor well-construction or operating practices? 
    3. Has the target shifted any of its environmental compliance, contamination or litigation risks to third parties, including insurance companies, sellers/buyers of assets or businesses, or joint venture partners, if any?
    4.  Is the target subject to SEC reporting? Are the target’s estimates of natural gas reserves and/or environmental risk, if applicable, supportable?
  2. For targets who have existing wells, consider the following:
    1. In what regions, states and municipalities are the target’s wells located? Have impact fees been imposed or proposed?
    2. If the wells are still generating flow-back, how is it managed?
      1. If the target relies on a wastewater treatment plant, can the plant continue to treat the wastewater in compliance with the Clean Water Act and/or state law?
      2. If the target uses injection wells, does it use fracking fluid that includes diesel fuel? Does the target have an underground injection permit? 
    3. Does the target monitor groundwater and/ or drinking water?
      1. Are there any impacts noted?
      2. Are there other potential sources of contamination in the area including abandoned wells? 
      3. Is there any proposed or ongoing investigation, remediation or other response action with respect to the impacted groundwater, including the provision of alternative drinking water supplies?
    4. Does the target disclose the chemical constituents (and relative amounts of such constituents) of its fracking fluid?
    5. Does the target have a Title V Clean Air Act permit? Does the gas well utilize “green completion” technology consistent with soon-to-be-required federal air regulations? 
  3. For targets who propose installing new wells, consider the following:
    1. In what regions, states and municipalities are the target’s proposed well sites located? Have impact fees been imposed or proposed?
      1. Is there a ban, moratorium or limit on new well installations or the number of wells installed by a single legal entity?)
      2. Are there proposed or enacted well set-back requirements that could effectively limit the target’s ability to install new wells?
    2. What will be the source of the fracking water supply?
    3. Will the target need a regional water withdrawal permit? Consider the timing and cost of permitting.I
    4. s any source water authorization subject to any low-flow (i.e., drought) restrictions that could impact the timing of fracking? 
  4. How will the flowback water be managed?
    1. Is injection feasible/permitted? Consider timing of applicable permit.
    2. Does the target plan on using fracking fluid that could contain diesel fuel?
      1. Consider the timing and cost of obtaining an injection permit, if necessary.
    3. Does the target have access to a wastewater treatment facility that can accept the flowback water? Consider any added wastewater transportation and treatment costs.
    4. Is the target planning on constructing a dedicated wastewater treatment plant? Consider capital costs and the timing and cost of permitting. 
    5. Will well installation require a construction permit under state air pollution laws and/or a Title V permit?
      1. Consider the timing and cost of permitting. Consider the cost of “green completions” and/or other required air emission control technology.
    6. Has the target performed baseline groundwater sampling of drinking water supplies?
      1. Are there any known impacts to groundwater in the vicinity of the proposed gas well(s)?
      2. Has the target evaluated whether there are any constituents in its fracking fluid that are present in the existing drinking water supply? Can the target make substitutions to its fracking fluid to avoid problems of proof?  

Conclusion

Investments in and acquisitions of businesses engaged in Marcellus Shale E&P are being conducted against a backdrop of evolving laws and regulations. Although it appears it will be some time before the full extent of environmental regulatory challenges associated with fracking in the Marcellus Shale can be well defined, by following the regulatory debate and by asking appropriate due diligence questions, investors can take the first steps in managing these challenges.