The Future of Hydraulic Fracturing Litigation

Shale Related Litigation and Regulatory Developments:

Stephanie Meadows American Petroleum Institute Washington, DC James Saiers Yale School of Forestry & Environmental Studies New Haven, CT James Thompson Vinson & Elkins LLP Houston, TX

Reprinted with Permission

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SHALE RELATED LITIGATION AND REGULATORY DEVELOPMENTS

Robert M. Schick, Larry Nettles, James Thompson, Gabrielle Sitomer, & Edward Duffy Vinson & Elkins, L.L.P.

SYNOPSIS

§ 1.01 Introduction ...........................................................................................................................3 

§ 2.01 Litigation Developments .......................................................................................................5 

[1]  Aggregation under the Clean Air Act ............................................................................5 

[a]  Summit Petroleum Corp. v. EPA ....................................................................................5 

[b]  Citizens for Pennsylvania’s Future v. Ultra Resources, Inc. .........................................7 

[c]  Conclusions ....................................................................................................................8 

[2]  Cases Addressing Causation and Harm .........................................................................9 

[a]  Strudley v. Antero Resources Corporation, et al., – Lone Pine motion granted and Case Dismissed ..............................................................................................................9 

[b]  Denial of Motions for MCMOs in Kamuck v. Shell and Roth v. Cabot Oil & Gas .....12 

[c]  Harris v. Devon Energy Prod. Co. ..............................................................................12 

[d]  Rodriguez v. Krancer ...................................................................................................13 

[e]  Hiser v. XTO Energy and Seismic Allegations ............................................................14 

[f]  Evenson, et al. v. Antero Resources Corporation, et al.– Motion to dismiss amended complaint on jurisdictional grounds granted................................................................15 

[3]  Preemption ...................................................................................................................17 

[a]  Northeast Natural Energy v. City of Morgantown, W.V. .............................................17 

[b]  New York .....................................................................................................................18 

[c]  Conclusions ..................................................................................................................19 

[4]  Butler v. Powers – Ownership of Shale Gas in Pennsylvania .....................................19 

[5]  Future Possibilities .......................................................................................................21 

§ 3.01 Regulatory Developments ...................................................................................................23 

[1]  Overview ......................................................................................................................23 

[2]  Federal Regulations .....................................................................................................23 

[a]  Possible regulation under the Safe Drinking Water Act ..............................................24 

[i]  EPA study plan ............................................................................................................25 

[ii]  Pavillion, Wyoming ground water contamination investigation .................................26 

[iii]  Dimock, Pennsylvania groundwater contamination investigation ...............................28 

[iv]  Disclosure requests ......................................................................................................29 

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[v]  Regulation of fluids using diesel fuel ..........................................................................29 

[b]  Possible mandatory disclosure under Toxic Substances Control Act (TSCA) ............30 

[c]  New emissions regulations under the Clean Air Act ...................................................31 

[d]  Regulation of wastewater under the Clean Water Act .................................................33 

[e]  BLM Proposed Regulations .........................................................................................34 

[3]  State and Local Regulations.........................................................................................35 

[a]  Aggregation..................................................................................................................35 

[b]  Water Withdrawal ........................................................................................................37 

[c]  Siting regulations for proximity to critical areas .........................................................38 

[d]  Prohibitions and regulation at the local level ...............................................................40 

[e]  Disclosure standards ....................................................................................................41 

§ 4.01 Conclusion ..........................................................................................................................44 

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§ 1.01 Introduction

Over the past decade, the United States has experienced a natural gas “revolution” of sorts. This revolution, however, is not so much reflected in the total volume of natural gas production as in how and from what sources natural gas is being produced. This is primarily due to advancements in and the increased use of innovative recovery techniques that have enabled producers to profitably recover gas from “unconventional” sources such as shale.

While industry analyses have returned varied estimates as to precisely how much technically recoverable gas is contained within the United States’ major shale formations1, most industry analysts agree that shale gas will play an important role in terms of meeting the nation’s energy needs in years to come. In fact, the U.S. Energy Information Administration (“EIA”) estimates that by 2035, shale gas will account for roughly 46% of the United States’ total natural gas supply.2 Shale has not, however, in years past been such a significant contributor. As illustrated in Table 1, historically the vast majority of natural gas produced in the United States has been recovered from “conventional” sources other than shale. Conventional sources are more easily recoverable because they have a relatively high degree of permeability which allows for gas to flow (or migrate across a pressure gradient) through a formation and into a wellbore. By contrast, shale is impermeable, meaning that gas in shale is essentially trapped in place and thus will not flow as does gas found in conventional sources. For many years this characteristic of shale prevented gas producers from recovering profitable quantities of gas from shale formations. But, with the advent of hydraulic fracturing and horizontal drilling, shale’s impermeability is no longer an impediment to development.

Hydraulic fracturing is a recovery technique that involves injecting water mixed with specially designed chemicals thousands of feet into the ground at extremely high pressures; which causes fractures to form in the shale surrounding the wellbore. As the water flows back to the wellhead, the chemicals mixed with the water leave behind “proppants” that hold open these fractures, thereby creating pathways for gas to flow within the otherwise impermeable shale.

1 See Ian Urbina, Geologists Sharply Cut Estimate of Shale Gas, N.Y. TIMES, Aug. 24, 2011, http://www.nytimes.com/2011/08/25/us/25gas.html; see also HARY VIDAS & BOB HUGMAN, AVAILABILITY, Economics AND PRODUCTION POTENTIAL OF NORTH AMERICAN UNCONVENTIONAL NATURAL GAS SUPPLIES 50 table 6 (Nov. 2008), available at http://www.ingaa.org/File.aspx?id=7878. 2 Richard Newell, EIA Adm’r, Shale Gas and the Outlook for U.S. Natural Gas Markets and Global Gas Resources Presentation to the Organization for Economic Cooperation and Development in Paris, France (June 21, 2001), available at http://photos.state.gov/libraries /usoecd/19452/pdfs/DrNewell-EIA-Administrator-Shale-Gas-Presentation-June212011.pdf.

Source: EIA Annual Energy Outlook 2012

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When combined with the use of horizontal and multi-directional drilling, hydraulic fracturing allows producers to recover exponentially greater volumes of gas than would be recoverable by way of vertical drilling. This has led to a relative boom in shale gas production, with reported average annual growth rates of 17 percent from 2000 to 2006 and 48 percent from 2006 to 2010.3 As visual evidence of this growth, consider the graphic below illustrating drilling in the Barnett Shale during that same time period.

Unsurprisingly, the rapid development and increased use of hydraulic fracturing has garnered considerable attention from citizens, environmental groups, state and local governments, and the media. As one might expect, not all of this attention has been positive. Take for example the 2010 film entitled “Gasland”—a documentary in which the film’s producers show a homeowner lighting his tap water on fire in explosive fashion while claiming that the cause of the phenomena was nearby gas wells that had been hydraulically fractured.4 Though many have questioned the validity of the claims and representations made in “Gasland,”5 it was still able to muster enough support to receive an Academy Award nomination.6

The fact of the matter is that the use of horizontal drilling and hydraulic fracturing as means of developing shale gas resources has sparked what is perhaps one of the most polarizing debates in our country. On the one hand, proponents of shale development argue that horizontal drilling and hydraulic fracturing pose minimal risk when carried out properly. These proponents further point to the technique’s ability to unlock what some have estimated to be decades worth of energy supply. On the other hand, hydraulic fracturing’s detractors cite to environmental concerns over the safety of injecting potentially toxic chemicals into the ground and the subsequent disposal thereof. Thus, it should be with little surprise that the rapid growth of shale

3 EIA Annual Energy Outlook 2011, 2, available at http://www.eia.gov/. 4 See Plot Summary for Gasland (2010), http://www.imdb.com/title/tt1558250/plotsummary, (last visited Jan. 20, 2012); see also Gasland Official Theatrical Trailer, http://www.youtube.com/watch?v=z0fAsFQsFAs (last visited Jan. 20, 2012). 5 See, e.g., Colorado Oil and Gas Commission Response to Gasland, available at http://cogcc. state.co.us/library/GASLAND%20DOC.pdf. 6 Mike Soraghan, Groundtruthing Academy Award Nominee ‘Gasland’, N.Y. Times, Feb. 24, 2011, http://www.nytimes.com/gwire/2011/02/24/24greenwire-groundtruthing-academy-award-nominee-gasland-33228.html?pagewanted=all.

Graphic 1: Drilling in the Barnett Shale from 2000 to 2010

Source: Shale Play Development History Animations available at http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm#shaleplay

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gas production has brought with it some unwanted consequences for energy industry participants; namely, an onslaught of lawsuits as well as increased regulation by state and local authorities. And, though this paper does not attempt to resolve the ongoing debate over horizontal drilling and hydraulic fracturing, it does provide an overview of recent litigation and regulatory developments relative to shale gas production in the United States.

§ 2.01 Litigation Developments

On the litigation front, a survey of the various jurisdictions with significant shale gas resources identified approximately forty (40) lawsuits that involve shale-related issues. These lawsuits can be categorized in a variety of ways. The procedural posture of the cases can generally be classified as: (1) an individual or class-action tort lawsuit, (2) a citizen/environmental action lawsuit, or (3) an industry challenge lawsuit. Factually, nearly all of these cases involve some type of environmental harm for which hydraulic fracturing is allegedly responsible: (1) air pollution; (2) groundwater or soil contamination; (3) surface water pollution; (4) excessive use of water and (5) seismic activity. Furthermore, the lawsuits implicate a wide variety of legal issues, including the regulatory authority of state and federal governmental bodies, statutory interpretation, evidence, discovery, and remedies.

This paper will focus on several key trends, which are discernible from cases that are currently pending or that were decided during the past year: (1) the turn against aggregation of operationally related facilities for Clean Air Act permitting purposes; (2) a series of cases showing the difficulty of establishing a causal link between hydraulic fracturing and harm to health or the environment; (3) increasing lawsuits against local governments’ prohibitions or regulations against hydraulic fracturing; and (4) states without extensive backgrounds in oil and gas law determining cases of first impression.

[1] Aggregation under the Clean Air Act

Among the most contentiously litigated issues by industry and environmental groups is the question of aggregating facilities under the Clean Air Act (“CAA”). As presently applied, many aspects of the CAA do not affect upstream oil and gas operations. That is because the primary focus of the CAA is to regulate “major source” facilities. Since individual wells and smaller related facilities do not normally produce enough emissions to qualify as major sources, such facilities have gone largely unregulated under the federal regime. The EPA, however, has asserted that certain facilities necessary for oil and gas exploration and production should be aggregated and treated as a single facility for purposes of the CAA, which would entail their regulation as “major source” facilities. Similarly, citizen action groups have initiated suit to require regulatory authorities to aggregate such facilities.

[a] Summit Petroleum Corp. v. EPA

In August of 2012, the United States Court of Appeals for the Sixth Circuit vacated the EPA’s determination to aggregate natural gas wells and a sweetening plant operated by Summit Petroleum. Summit owned and operated a natural gas sweetening plant and approximately one

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hundred gas production wells spread out over a forty-three square mile area.7 The lawsuit came in response to a decision by the EPA to apply the CAA’s major source permitting requirements to one hundred natural gas wells and a sweetening facility spread throughout an approximate 43 square mile area in Michigan. The wells at issue in Summit would not individually be subject to major source permitting under the CAA. Nonetheless, in response to a petition from the Michigan Department of Environmental Quality (MDEQ) and Summit Petroleum, the EPA determined that the facilities should be treated as a single facility for CAA permitting purposes.8

The CAA requires a “major source” of air pollution to obtain a Title V operating permit, with “major source” defined as “any stationary facility or source of air pollutants which directly emits, or has the potential to emit, one hundred tons per year of any pollutant.”9 The EPA allows for the aggregation of multiple facilities when they are (1) under common control; (2) located on contiguous or adjacent properties; and (3) are part of the same major industrial grouping.10 Summit and MDEQ requested that the EPA determine whether the sweetening plant and associated gas wells constituted a major source, and the EPA indicated that although the facilities were under common control and part of the same major industrial grouping, they were not on contiguous properties, and it was unclear whether such properties were adjacent.11 Although it initially indicated that proximity was the primary factor in determining whether facilities were located on adjacent properties, the EPA refrained from making a decision as to whether Summit’s facilities should be aggregated for over two years.12 Then in July of 2009, the EPA stated that it might not focus primarily on physical proximity to determine whether facilities were located on adjacent properties.13 And in September, the EPA issued a determination that the sweetening plant and gas wells constituted a single stationary source and therefore a major source, emphasizing that the functional interrelatedness of facilities, rather than merely the distance between them, was a key factor in determining whether to treat the facilities as a single source.14

Summit Petroleum brought suit in the Sixth Circuit, seeking vacatur of the EPA’s determination as inconsistent with the EPA’s existing regulations.15 In 1 2-1 opinion vacating the EPA’s determination, the court noted that the only issue contested was whether Summit Petroleum’s facilities were located on “adjacent” property, and citing to dictionary definitions and judicial opinions for support, concluded that the term “adjacent” is unambiguous and relates to physical proximity.16 The EPA’s determination that “adjacent” could embrace facilities that

7 Summit Petroleum Corp. v. EPA, __ F.3d __, Nos. 09-4348; 10-4572, 2012 WL 3181429, at *1 (6th Cir. Aug. 7, 2012). 8 See Letter from Cheryl L. Newton, EPA Dir. of Air and Radiation, to Scott Huber, Summit Petroleum Corp. (Oct. 18, 2010) (copy on file with author). 9 42 U.S.C. §§ 7602(j); 7661a(a). 10 40 C.F.R. § 71.2 11 Memorandum from William L. Wehrum, Acting Assistant Adm'r, to Reg'l Adm'rs I–X (Jan. 12, 2007) available at http://www.eenews.net/public/25/ 12769 /features/documents/2009/ 10/ 13/document_pm_02.pdf (last visited May 16, 2012) (Wehrum Memorandum). 12 Summit Petroleum, 2012 WL 3181429, at *3-4. 13 Id. at *4-5. 14 Id. at *5-6. 15 Id. at *6. 16 Id. at *7-10. In particular, the Sixth Circuit cited to the Supreme Court’s decision in in Rapanos v. United States, 547 U.S. 715, 720-24 (2006) as support for its position. Id. at *9.

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were not in close proximity, but that were functionally interrelated, was not entitled to deference because it was inconsistent with the unambiguous meaning of the term “adjacent.”17 The court further noted that the EPA’s longstanding emphasis on functional relatedness did not entitle it to greater deference, that the EPA’s determination was inconsistent with earlier positions it had taken, and that the interpretation was inconsistent with the EPA’s Title V plan.18

Judge Moore dissented and would have upheld the EPA’s determination, emphasizing that greater deference was appropriate.19 The dissent noted that although it related to physical distance, the term “adjacent” was nevertheless an ambiguous term and that factors like functional interrelatedness could inform a determination as to whether multiple facilities were in fact located on adjacent properties.20 Additionally, pipeline ran between the wells and the sweetening plant, showing that there was a “physical dimension” to the functional interrelatedness of the facilities.21 In short, functional interrelatedness “does not replace proximity, but serves as a means of determining proximity.”22 In light of the ambiguity inherent in the term “adjacent,” the dissent concluded it would be appropriate to defer to the EPA’s determination, which Judge Moore believed to be reasonable.23 The dissent further explained that such a result would be consistent with regulatory history and public policy.24

EPA released a memorandum written on December 21, 2012 explaining how it would respond to the ruling. The agency said it would follow the court’s aggregation determination process in Sixth Circuit states but continue to follow its current guidance on making aggregation determinations in other states.25

[b] Citizens for Pennsylvania’s Future v. Ultra Resources, Inc.

Another aggregation case making its way through the courts is Citizens for Pennsylvania’s Future v. Ultra Resources, Inc. (“PennFuture”), in which environmental action groups have challenged the decision of the Pennsylvania Department of Environmental Protection to not aggregate certain facilities under the CAA and under additional regulations promulgated by the Pennsylvania Environmental Quality Board. In their complaint, plaintiffs assert that Ultra’s wells, pipelines, and compressor stations operating within the Marshlands Play are “operationally interdependent,” and thus their collective emissions should determine whether they are subject to the CAA’s major source permitting requirements.26 Plaintiffs further assert that the collective emissions of those facilities exceed the thresholds for NOx and other pollutants established by the CAA.27 Based on these allegations, Plaintiffs claim that Ultra has

17 Summit Petroleum, 2012 WL 3181429, at *10-11. 18 Id. at *11-16 19 Id. at *16 (Moore, J., dissenting). 20 Id. at *17-18. 21 Id. at *18. 22 Id. at *19. 23 Summit Petroleum, 2012 WL 3181429, at *19-20. 24 Id. at *20-22. 25 Environmental Protection Agency, Memorandum, Applicability of the Summit Decision to EPA Title V and NSR Source Determinations, from Stephen D. Page, December 21, 2012. 26 See Plaintiffs’ Complaint at ¶ 86, Citizens for Pennsylvania’s Future v. Ultra Resources, Inc., 4:11-cv-01360 (M.D. Pa. July 21, 2011). 27 See id. at ¶ 92.

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been operating its Marshlands Play wells, pipelines, and compressor stations in violation of the CAA by failing to obtain a new source review permit.28

Defendants filed a motion to dismiss on grounds that that the district court lacked subject-matter jurisdiction or that the court should abstain from deciding a question of state law necessary to reach the merits of the federal question.29 Defendants argued that implementation and administration of the EPA remains a state responsibility and that the Pennsylvania Environmental Quality Board should be able to first pass on the decision of the Department of Environmental Protection, prior to any judicial action.30 The court denied the motion, holding that it had subject-matter jurisdiction over the claims and that abstention was not warranted.31 After determining that it would generally have jurisdiction over the type of claim presented, based on a plain reading of the statute, the court turned to Ultra’s exhaustion arguments, expressing concern that plaintiffs would be left without a remedy if the court did not exercise jurisdiction because the time to appeal the decision to the Environmental Quality Board had expired. Although the court recognized that its holding would disincentivize plaintiffs from pursuing appeals through the state regulatory framework, the court determined that there was no express exhaustion requirement in Section 304(a)(3) of the Clean Air Act and the court refused to read such a requirement into the statute.32

[c] Conclusions

The Summit Petroleum and PennFuture cases ultimately boil down to where and how state and federal regulatory agencies should draw the line as to whether two or more emitting sources are contiguous or adjacent facilities as those terms are employed by the CAA.33 Although successful in the Sixth Circuit, industry groups might not be able replicate that success in other courts that may consider similar aggregation cases. The EPA could also petition for certiorari before the Supreme Court, and as was previously mentioned, the EPA will implement the Sixth Circuit’s decision only in within the Sixth Circuit. Judge Moore’s dissenting opinion identifies a possible approach that a different court could take in either PennFuture or another case. Whether the court in PennFuture follows the lead of the Sixth Circuit, assuming it is able to reach the merits, will therefore likely have significant implications. The consequences of aggregating such facilities under the CAA would be significant. For one, owners and operators of multiple smaller facilities would be subjected to the expensive and time consuming new source review process which includes, among other things, bringing such facilities into

28 See id. at ¶ 3. Defendants claim the court lacks subject matter jurisdiction by characterizing Plaintiffs’ suit as a collateral attack on the Pennsylvania Department of Environmental Protection and an impermissible attempt to “bypass appeal to the [Pennsylvania Environmental Hearing Board].” Id. 29 Plaintiffs’ Memorandum of Law in Support of its Motion to Dismiss at *9, Citizens for Pennsylvania’s Future v. Ultra Resources, Inc., No. 11cv01360 (M.D. Pa. Oct. 6, 2011). 30 Plaintiffs’ Reply Memorandum of Law in Support of its Motion to Dismiss at *5-9, Citizens for Pennsylvania’s Future v. Ultra Resources, Inc., No. 11cv01360 (M.D. Pa. Nov. 21, 2011). 31 Memorandum Opinion, Citizens for Pennsylvania’s Future v. Ultra Resources, Inc., No. 11cv01360 (M.D. Pa. Sept. 24, 2012). 32 Id. 33 See 40 C.F.R. § 71.2 (“Major source means any stationary source (or any group of stationary sources that are located on one or more contiguous or adjacent properties, and are under the common control of the same person (or persons under common control)), belonging to a single major industrial grouping.”).

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compliance with the CAA’s lowest achievable emission rates. In the meantime, aggregation will likely continue to be a hot issue.

[2] Cases Addressing Causation and Harm

The majority of lawsuits involving hydraulic fracturing are tort lawsuits brought by private plaintiffs, alleging a variety of harms. The most common claims typically allege that hydraulic fracturing and its related processes are responsible for causing excessive noise, increased seismic activity, air, soil, and groundwater contamination resulting in personal injury/illness, diminution in property value, death of animals and livestock, mental anguish, and emotional distress. In most instances plaintiffs package these factual allegations into causes of action for trespass, nuisance, negligence, negligence per se, gross negligence, and strict liability. And, in terms of the relief sought, most of the plaintiffs involved seek—in addition to compensatory and punitive damages—some form of injunctive relief, as well as remediation and the establishment of medical monitoring funds. Though most of the presently pending cases that fall in this category are in the preliminary stages of litigation, there have still been some notable developments worthy of discussion.

Perhaps the most notable recent trend with respect to these lawsuits is the difficulty plaintiffs have encountered in establishing causation between hydraulic fracturing and the alleged harm that is the subject of the lawsuits. Three lawsuits demonstrate the fairly stringent scrutiny that courts have applied in determining whether plaintiffs have provided sufficient evidence of causation, while a fourth further emphasizes the importance of causation evidence in establishing a viable claim based on harms allegedly caused by hydraulic fracturing.

[a] Strudley v. Antero Resources Corporation, et al., – Lone Pine motion granted and Case Dismissed

Perhaps the most notable developments in the area of shale-related tort litigation have arisen from Strudley v. Antero Resources Corporation, et al.34 In Strudley, the plaintiffs sued the owner and operator of wells located near the plaintiffs’ residence in Silt, Colorado.35 In their Amended Complaint, Plaintiffs alleged that Defendants have caused “hazardous pollutants and industrial and/or residual waste … to be discharged into … the air, ground, and aquifer” from which Plaintiffs obtain their water supply.36 In conjunction with these allegations, Plaintiffs asserted claims of trespass, nuisance, negligence, negligence per se, and strict liability.37 Thus, in terms of the allegations and claims involved, Strudley is fairly representative of shale-related tort litigation as a whole. That being said, recent developments in the case have given it added significance. Specifically, on November 9, 2011, Defendants successfully obtained a Lone Pine order wherein the Colorado state court ordered that plaintiffs must, “before full discovery and other procedures are allowed, [] make a prima facie showing of exposure and causation[.]”38 To

34 Strudley v. Antero Resources Corp., et al., 2011cv2218 (Colo. Denver Dist. Ct. filed Mar. 24, 2011). 35 Amended Complaint, at ¶¶ 1, 12-13, Strudley v. Antero Resources Corp., et al., 2011cv2218 (Colo. Denver Dist. Ct. Apr. 29, 2011). 36 Id. at ¶ 50(a). 37 See generally id. 38 Modified Case Management Order ¶ 4, Strudley v. Antero Resources Corp. et al., 2011cv2218 (Colo. Denver Dist. Ct. Nov. 10, 2011) (Modified Case Management Order).

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appreciate the significance of this order, it helps to understand where such orders originate and how they affect a plaintiff’s burden of proof in toxic-tort cases.

By way of background, Lone Pine orders derive their name from the 1986 toxic-tort case Lore v. Lone Pine Corp.39 In that case, the court issued a modified case management order that required Plaintiffs to submit sufficient documentation to create a prima facie case as to Plaintiffs’ claims for exposure and damages before the court would permit the case to go forward.40 After being granted multiple extensions, Plaintiffs were unable to produce sufficient documentation.41 Accordingly, the court dismissed the case on the grounds that Plaintiffs’ claims lacked sufficient evidentiary bases to proceed.42 Since then, many courts—like the Strudley court—have followed suit by issuing similar orders that preclude further proceedings until the plaintiff makes a prima facie showing of exposure, injury, and causation through expert affidavits.

How a Lone Pine order affects, if at all, a plaintiff’s burden of proof with respect to causation is also helpful in understanding the significance of such an order. On that point, it should be noted that in any case, Lone Pine order or not, a toxic-tort plaintiff, in order to ultimately prevail, must come forward with evidence sufficient to demonstrate that a defendant’s actions caused the exposure and resultant harms plaintiff alleges to have suffered. Thus, while a Lone Pine order does not change a plaintiff’s ultimate burden, it does change the traditional sequencing in which a plaintiff must come forward with evidence to meet that burden. Practically speaking, this means that plaintiffs must come forward with evidence earlier on in litigation and presumably without the benefits of having engaged in full-blown discovery. It also means that plaintiffs must prove that they conducted diligence early on—i.e. before filing suit—that included a site-specific inquiry as to harm and causation.

In the context of shale-related tort litigation, this presents a considerable challenge. This difficulty stems from the fact that very little hard evidence has been produced that demonstrates hydraulic fracturing is, in and of itself, capable of causing the type of contamination and exposure alleged in shale-related tort cases like that of Strudley. This may not be as big of an issue where there is clear evidence of poor well construction or where an undisputed chemical spill is to blame. But, where such is not the case, the absence of reliable evidence upon which exposure and causation can be proved is problematic for plaintiffs. In fact, as noted by the Strudley court, “[f]ocusing on whether Plaintiffs can produce admissible evidence concerning exposure and causation may eliminate or sharply curtail this case.”43

On that note, the arguments offered by both Defendants and Plaintiffs in support of and in opposition to the court’s Lone Pine order in Strudley are worthy of some attention here. On the one hand, the defendants argued that the order was warranted given the vague nature of the plaintiffs’ allegations and in light of contradictory findings by the Colorado Oil and Gas Conservation Commission that the wells at issue had not been contaminated and that plaintiffs’

39 See No. L-33606-85, 1986 WL 637507 (N.J. Sup. Ct. Nov. 18, 1986). 40 See id. at 1-2. 41 See id. at 3-4. 42 See id. at 4. 43 Modified Case Management Order at ¶ 7.

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exposure was therefore unlikely.44 On the other hand, the plaintiffs opposed Defendants’ motion on the grounds that Lone Pine orders are typically only issued in mass tort cases involving multiple plaintiffs and multiple defendants, and only when there is a demonstrated history of the plaintiffs’ refusal to provide basic information concerning their claims.45 Nevertheless, the court agreed with Defendants that a Lone Pine order was appropriate in light of the complexity of the lawsuit, the fact that the plaintiffs were asserting injuries resulting from Defendants’ hydraulic fracturing activities, and Defendants’ evidence adduced to date that cast doubt as to Plaintiffs’ claims of exposure.46 Thus, the Strudley court’s Lone Pine order is even more significant to the extent that it constitutes an expansion of the typical circumstances under which such orders are usually granted.

In response to the Lone Pine Order and Defendants’ subsequent motion to dismiss the suit, Plaintiffs submitted a compilation of maps, photos, medical records, water and soil samples, and an affidavit from Dr. Thomas Kurt, who opined only that further discovery was warranted to determine whether hydraulic fracturing was responsible for the complained-of injuries.47 The samples showed that some levels of potentially hazardous compounds were present in Plaintiffs’ property, but there was no evidence showing any probability of a causal connection between Plaintiffs’ injuries and their exposure to drilling activities.48

Due to the weakness of the evidence submitted, especially the absence of any conclusion by Dr. Kurt that Plaintiffs’ injuries could have been caused by Defendants’ drilling, the court held that Plaintiffs did not comply with the Lone Pine Order and dismissed the case with prejudice on May 9, 2012.49 In so holding, Judge Frick stated that “Plaintiffs’ requested march towards discovery without adequate proof of causation of injury is precisely what the MCMO was meant to curtail.”50

44 See Defendants’ Motion for Modified Case Management Order at *4, Strudley v. Antero Resources Corp., et al., 2011cv2218 (Colo. Den. Dist. Ct. Sept. 19, 2011). 45 See Plaintiffs’ Memorandum of Law in Opposition to Defendants’ Motion for a Modified Case Management Order at 9-14, Strudley v. Antero Resources Corp. et al., 2011cv2218 (Colo. Den. Dist. Ct. Oct. 24, 2011). 46 See Modified Case Management Order at ¶¶ 1-2, 5. 47 Order Granting Defendants’ Motion to Dismiss or, in the Alternative, for Summary Judgment 3, Strudley v. Antero Resources Corp., 2011cv2218 (Colo. Den. Dist. Ct. May 9, 2012). 48 Id. at 3-5. 49 Id. at 6-7. 50 Id. at 7.

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[b] Denial of Motions for MCMOs in Kamuck v. Shell and Roth v. Cabot Oil & Gas

In the wake of the Colorado court’s granting of a Modified Case Management Order in Strudely and the subsequent dismissal of the suit with prejudice, defendants in tort lawsuits with allegations arising from hydraulic fracturing appeared to have a powerful tool at their disposal. This sentiment may have been tempered somewhat, however, by two recent orders in a pair of federal lawsuits pending in the Middle District of Pennsylvania: Kamuck v. Shell Energy Holdings GP, LLC51 and Roth v. Cabot Oil & Gas Corp.52 In both cases, which involved a variety of tort claims arising from oil and gas development activities in the area, Magistrate Judge Carlson denied the defendants’ motions for Lone Pine Case Management Orders, each filed in the beginning of the respective discovery periods.

In Roth, the court characterized such orders as “unusual and burdensome” and stated that they were not warranted at an early stage of proceedings, but that the court had ample tools at its disposal to ensure that defendants were not unduly burdened by discovery.53 The court identified the following as factors to consider in determining whether to enter a Modified Case Management Order: (1) the posture of the litigation; (2) case management needs; (3) the bearing of external agency decisions; (4) the availability of other procedures that have been specifically provided for by rule or statute; and (5) the type of injury alleged and its cause.

The court also noted that such orders were generally appropriate in mass-tort situations, involving large numbers of parties.54 Furthermore, the Kamuck court denied the motion without prejudice and indicated that defendants were free to file a similar motion if discovery proved overly burdensome.55

Roth and Kamuck suggest that federal courts may be more reluctant to enter Modified Case Management Orders than would state courts, at least at the early stages of a lawsuit. Given Judge Carson’s statements that other means were available to limit discovery burdens on the defendant and the possibility of re-filing such motions at a later date, the precise parameters of the court’s holdings remain unclear. The manner in which the court manages discovery disputes in these lawsuits—and whether other federal courts will find Roth and Kamuck persuasive—will be key issues in the future use of Lone Pine orders.

[c] Harris v. Devon Energy Prod. Co.

The plaintiffs in Harris v. Devon Energy Prod. Co. also appeared to have difficulty in procuring evidence that would establish causation of their claims, and voluntarily moved to have the suit dismissed without prejudice. At issue in Harris is the alleged contamination, evidenced by groundwater testing, of a couple’s property, which they claim resulted from hydraulic fracturing.56 The plaintiffs brought nuisance, negligence, trespass, strict liability, fraud, and fraudulent concealment claims against Devon Energy Production and sought damages based on

51 No. 4:11-cv-01425-MCC (M.D. Pa. Sept. 5, 2012). 52 No. 3:12-cv-00898-JEJ (M.D. Pa. Oct. 15, 2012). 53 Roth, No. 4:11-cv-01425-MCC, at *4-5, 17. 54 Id. at *9. 55 Kamuck, No. 3:12-cv-00898-JEJ, at *3. 56 Plaintiffs’ Complaint 1-3, Harris v. Devon Energy Prod. Co., No. 4:10-cv-00708 (E.D. Tex. Dec. 15 2010 filed).

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lost property value, lost well water, emotional harm, .medical monitoring, and remediation, as well as exemplary damages.57 Devon Energy Production moved for summary judgment, alleging that the contamination alleged was not scientifically possible and that there was no issue of material fact as to the causation element of Plaintiffs’ causes of action.58 The court denied the motion as premature, noting that no discovery had occurred and that Plaintiffs should have an opportunity for discovery before further consideration of the motion.59

After the lawsuit was filed, testing of Plaintiffs’ well water demonstrated that water contamination had been reduced significantly since earlier testing conducted when suit was filed, and that the contamination level was no longer at toxic levels.60 Rather than contest the new evidence, Plaintiffs opted to seek dismissal of the suit, but without prejudice, so that they could re-file the same claims later, possibly if more favorable evidence turned up.61 Devon Energy Production resisted this motion, likely believing that a grant of summary judgment was likely and wished to avoid the possibility of Plaintiffs later filing suit. Despite Devon Energy Production’s assertion that it would be prejudiced if the Plaintiffs’ suit was dismissed without prejudice, the court granted Plaintiffs’ motion.62 Devon Energy Production has appealed this order.63 Although Plaintiffs were successful in obtaining this order and could file a similar lawsuit in the future, the case demonstrates the difficulty facing plaintiffs in establishing that hydraulic fracturing is responsible for harm that is suffered.

[d] Rodriguez v. Krancer

A lawsuit recently filed in the Middle District of Pennsylvania, Rodriguez v. Krancer, implicates a particular type of evidence often necessary to establish causation between hydraulic fracturing and physical illnesses suffered by plaintiffs. Rodriguez, a doctor practicing in Pennsylvania with experience in treating patients exposed to contaminated water, has challenged a state law known colloquially as the “Medical Gag Rule,” that restricts practitioners from receiving information from gas drilling companies.64 Dr. Rodriguez alleges that the restrictions 57 Id. at *3-9. 58 Defendant’s Motion for Summary Judgment 2, Harris v. Devon Energy Prod. Co., No. 4:10-cv-00708 (E.D. Tex. May 26, 2011 filed). 59 Report and Recommendation of Magistrate Judge, at *1, Harris v. Devon Energy Prod. Co., No. 4:10-cv-00708 (E.D. Tex. July 19, 2011 filed); Memorandum Adopting Report and Recommendation of Magistrate Judge, Harris v. Devon Energy Prod. Co., No. 4:10-cv-00708, at 1 (E.D. Tex. Aug. 11, 2011 filed). 60 Report and Recommendation of Magistrate Judge 2-3, Harris v. Devon Energy Prod. Co., No. 4:10-cv-0078 (E.D. Tex. filed Dec. 29, 2011). 61 Plaintiffs’ Motion to Dismiss Without Prejudice, Harris v. Devon Energy Prod. Co., No. 4:10-cv-00708 (E.D. Tex. filed Dec. 6, 2011). 62 Order Adopting Report and Recommendations for Motion to Dismiss, Harris v. Devon Energy Prod. Co., No. 4:10-cv-0078 (E.D. Tex. filed Jan. 25, 2012); Report and recommendation of Magistrate Judge, Harris v. Devon Energy Prod. Co., No. 4:10-cv-0078 (E.D. Tex. filed Dec. 29, 2011). 63 Defendants’ Notice of Appeal, Harris v. Devon Energy Prod. Co., No. 4:10-cv-0078 (E.D. Tex. filed Feb. 9, 2012). The case number in the Fifth Circuit is 12-40137. 64 Plaintiff’s Complaint, Rodriguez v. Krancer, No. 3:12-cv-01458-UN2, at 1-3 (M.D. Pa. July 27, 2012 filed); see generally 58 P.S. § 601.101 et seq. The text of the statute provides:

If a health professional determines that a medical emergency exists and specific identity and amount of any chemicals claimed to be a trade secrete or confidential proprietary information are necessary for emergency treatment, the vendor, service provider or operator shall immediately disclose the information to the health professional upon a verbal acknowledgement by the health professional that the information may not be used for purposes other than the health needs asserted and that the health professional shall maintain the

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imposed by this statute violate the First and Fourteenth Amendments to the Constitution and would require him to breach the ethical obligations of a medical professional.65 Specifically, Dr. Rodriguez argues that “the Medical Gag Rule is an unconstitutionally overbroad content-based regulation of speech in that it imposes on plaintiff the requirement to enter into a confidentiality agreement as a condition precedent to receive information needed for the ethical and competent treatment of a patient . . . .”66 Dr. Rodriguez further explained in his complaint that he intends to “alert the public, in the broadest possible manner, of known dangers posed by high-volume hydraulic fracturing.”67 Defendants have filed a motion to dismiss, based largely on Dr. Rodriguez’s alleged lack of standing.68

The statutory and regulatory rules governing the disclosure of components in hydraulic fracturing fluids have undergone significant transformation over the last several years, and Rodriguez is one of several lawsuits that have challenged these disclosure rules as overly protective of industry, especially with respect to trade secret protection. Dr. Rodriguez and similarly situated plaintiffs believe that such disclosure will help to determine whether there is a causal link between exposure to hydraulic fracturing fluids and particular illnesses and whether (and to what extent) hydraulic fracturing is responsible for any groundwater contamination.

[e] Hiser v. XTO Energy and Seismic Allegations

Although many studies commissioned by governmental bodies and non-governmental entities have lessened concerns related to alleged groundwater contamination arising from hydraulic fracturing, there is less research addressing seismic activity—which some say results from hydraulic fracturing. It is therefore possible that seismic activity will become an increasingly common allegation in tort suits related to hydraulic fracturing. A possible forerunner of such cases is Hiser v. XTO Energy, Inc. in which the plaintiff-landowner alleged that vibrations from nearby drilling operations damaged her home, brining negligence, trespass, and nuisance claims.69

The defendant moved for summary judgment, arguing that (1) it had not caused the damage; (2) any causation was not proximate; and (3) any harm was unforeseeable.70 The court denied the motion in on August 5, 2012.71 The plaintiff’s expert testimony, by an engineer who examined the home and attributed foundation and other damage to the nearby operations, was a significant piece of evidence, and the defendant argued this testimony was nevertheless

information as confidential. The vendor, service provider or operator may request, and the health professional shall provide upon request, a written statement of need and a confidentiality agreement from the health professional as soon as circumstances permit, in conformance with regulations promulgated under this chapter.

65 Plaintiff’s Complaint, 4, 9-11, Rodriguez v. Krancer, No. 3:12-cv-01458-UN2 (M.D. Pa. July 27, 2012 filed). 66 Plaintiff’s Complaint 12, Rodriguez v. Krancer, No. 3:12-cv-01458-UN2 (M.D. Pa. July 27, 2012 filed). 67 Id. at 13. 68 Defendant’s Motion to Dismiss, Rodriguez v. Krancer, No. 3:12-cv-01458-UN2 (M.D. Pa. Dec. 17, 2012). 69 No. 4:11-cv-00517-KGB (E.D. Ark. Aug. 14, 2012) (denying motion for summary judgment). It does not appear that hydraulic fracturing was actually performed at this well-site, but as discussed below, jurors inquired as to whether hydraulic fracturing did take place. 70 Id. at *1. 71 Id.

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insufficient to establish proximate causation.72 The court also emphasized that the testimony of the plaintiff herself was probative of causation.73 As to foreseeability, the court relied on Arkansas precedent, which held that harm arising from drilling operations to nearby property owners was foreseeable.74

A jury found for the plaintiff and returned a verdict for $100,000 in compensatory damages and $200,000 in punitive damages.75 Defendants moved for judgment as a matter of law, but the motion was denied on January 18, 2013.76 Interestingly, Defendants argued in moving for judgment as a matter of law or for a new trial that certain jurors had improperly inquired whether hydraulic fracturing was used on the subject wells.77 Counsel for the defendants noted that the word “fracking” was not used once during trial and should not be an issue in the case, and that if the jurors were inquiring about it, they were being swayed by outside information, presumably that the juror(s) had been exposed to prior to trial.78 Whether and to what extent the jurors discussed hydraulic fracturing is now a key issue in the resolution of post-trial motions pending before the court. Furthermore, Hiser may be indicative of future trends, in which allegations of seismic damage, become increasingly common.

[f] Evenson, et al. v. Antero Resources Corporation, et al.– Motion to dismiss amended complaint on jurisdictional grounds granted

Another case involving Antero Resources Corporation—Evenson, et al. v. Antero Resources Corporation, et al, though not addressing causation, demonstrates that plaintiffs are often unable to seek particular remedies.79 In Evenson, Plaintiffs complained that Defendants’ operations at the Watson Ranch Pad near the town of Battlement Mesa, Colorado are responsible for releasing “a strong odor” that has caused nearby residents to experience “burning eyes and throat and dizziness”80 which has in turn prevented them from “opening their doors and windows in the evenings and at night.”81 Interestingly, the remainder of the allegations were prospective in nature and are based on Plaintiffs’ belief that Defendants’ ongoing and future operations are “likely to cause releases, spills and discharges of combustible gases, hazardous chemicals and industrial wastes”82—all of which the plaintiffs alleged have and will continue to attach “a stigma” resulting in diminished property values.83 Notably, however, the plaintiffs packaged

72 Id. at *1-2 73 Id. at *4-5 74 Id. at *6. 75 Judgment in Favor of Ruby Hiser, Hiser v. XTO Energy, Inc., No. 4:11-cv-00517-KGB (E.D. Ark. Sept. 21, 2012). 76 Order Denying Defendants’ Renewed Motion for Judgment as a Matter of Law, Hiser v. XTO Energy, Inc., No. 4:11-cv-00517-KGB (E.D. Ark. Jan. 18, 2013). 77 Brief in Support of Defendants’ Motion for Permission to Contact Jurors after the Verdict, Hiser v. XTO Energy, Inc., No. 4:11-cv-00517-KGB (E.D. Ark. Aug. 30, 2012). 78 Id. at *3. 79 Class Action Complaint and Jury Demand, Evenson, et al. v. Antero Resources Corp., et al., 2011cv5118 (Colo. Den. Dist. Ct. July 20, 2011). 80 Id. at ¶ 39. 81 Id. at ¶ 40. 82 Id. at ¶ 45 (emphasis added). 83 Id. at ¶ 57.

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these allegations into causes of action for “diminution in value of real property,”84 “medical monitoring,”85 and “equitable relief.”86

In response to these allegations, the Evenson defendants filed a motion to dismiss alleging multiple bases upon which dismissal was warranted.87 With respect to the complaint as a whole, Defendants argued two points: (1) that Plaintiffs’ complaint failed to state a claim given that diminution in value of real property, medical monitoring, and equitable relief are remedies and not causes of action,88 and (2) that all of Plaintiffs’ claims were speculative in nature and thus not ripe for adjudication.89 Defendants also challenged the individual claims asserted by Plaintiffs, arguing that: (1) Plaintiffs’ cause of action for medical monitoring is not recognized by Colorado courts;90 (2) Plaintiffs’ claim for diminution of property value failed to plead any actual injury to Plaintiffs’ properties;91 and (3) Plaintiffs’ claim for equitable relief impermissibly impose upon the Colorado Oil and Gas Conservation Commission and its powers to regulate development of Colorado’s natural resources.92

In addressing Defendants’ arguments, the court agreed with the defendants that “Plaintiffs’ three purported claims … are essentially damages or remedies, not claims.”93 Furthermore, the court acknowledged additional deficiencies in plaintiffs’ complaint; namely, that, “with one exception, plaintiffs fail to plead actionable conduct by defendants.”94 In doing so, the court also noted that, even as a remedy, it is questionable whether medical monitoring is recognized in Colorado.95 The court further noted that diminution in property value resulting from Plaintiffs’ alleged “stigma” of nearby gas drilling operations “is not actionable … absent a recognized cause of action such as trespass or nuisance.”96 And, with regard to the “one exception”—i.e. Plaintiff’s allegations of exposure to noxious fumes from the Watson Ranch Pad—the court notes that even those allegations are deficient to the extent plaintiffs “fail to specifically plead that they were among the residents so exposed, that they suffered any physical or medical consequences from such exposure, or that any health professional has recommended to them future testing or evaluations.”97

Nonetheless, despite recognizing these deficiencies, the court did not dismiss the lawsuit but rather granted plaintiffs leave to amend with a deadline of doing so by January 6, 2012 (subsequently extended to January 31, 2012).98 On January 31, 2012, plaintiffs filed an amended 84 Id. at ¶ 55-64. 85 Id. at ¶ 65-74. 86 Id. at ¶ 75-80. 87 See Antero Defendants’ Motion to Dismiss, Evenson et at. v. Antero Resources Corp., et al., 2011cv5118 (Colo. Den. Dist. Ct. Sept. 15, 2011). 88 See id. at 3. 89 See id. 90 See id. 91 See id. 92 See id. 93 Order Entering Defendants’ Motion to Dismiss 1, Evenson et al. v. Antero Res. Corp., et al., 2011cv5118 (Colo. Den. Dist. Ct. Dec. 22, 2011). 94 See id. 95 See id. 96 Id. at 2. 97 Id. at 1. 98 See id.

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Complaint.99 Notably, plaintiffs state only one cause of action for “equitable relief” wherein they seek an injunction against defendants.100 On August 21, 2012, the trial court granted Defendants’ motion to dismiss the case on jurisdictional grounds, concluding that the court lacked the jurisdiction to award the remedies sought by Plaintiffs.101

[3] Preemption

As shale gas production and development has skyrocketed, federal, state, and local government have also manifested their concern by enacting bans, moratoriums, and by engaging in other efforts to restrict the use of the techniques. One of the most common state and local governmental responses to environmental concerns over the use of hydraulic fracturing has been to ban its use within a state’s or municipality’s geographical boundaries. As expected, such bans have been met with considerable opposition by energy industry participants—many of whom have filed suit.102 Although municipal regulations in several states have been challenged, the litigation experiences in two states—West Virginia and New York—provide an interesting contrast in the way that courts in those states have addressed challenges to local regulations.

[a] Northeast Natural Energy v. City of Morgantown, W.V.

Among those lawsuits, Northeast Natural Energy v. City of Morgantown, W.V. is notable in that the plaintiff energy company ultimately prevailed on its claim that a municipal ordinance was preempted by state law.103

On June 21, 2011, the Morgantown City Council enacted an ordinance that banned all oil and gas drilling operations utilizing horizontal drilling and hydraulic fracturing within a one mile radius of the City of Morgantown.104 Several months earlier, however, the West Virginia Department of Environmental Protection (“WVDEP”) had issued Northeast Natural Energy (“Northeast”) permits to horizontally drill and hydraulically fracture leased well sites in Morgantown Industrial Park located just outside the Morgantown City limits.105 Northeast quickly filed suit to enjoin the ban while noting that the Morgantown ban was a “death-blow” to all those possessing an interest in Marcellus shale gas in that area.106 In doing so, Northeast argued that the ban was both unconstitutional and preempted by state law that vests sole authority in the WVDEP to regulate in the areas of oil and gas exploration and environmental

99 First Amended Class Action Complaint and Jury Demand, Evenson et al. v. Antero Res. Corp., et al., 2011cv5118 (Colo. Den. Dist. Ct. Jan. 31, 2012). 100 See id. at 17. 101 102 See, e.g. Northeast Natural Energy v. City of Morgantown, W.V., No. 11-c-411 (Cir. Ct. Monongalia County June 23, 2011); Jeffrey v. Ryan, No. 2012-001254 (N.Y. Sup. Ct., Broome County May 30, 2012), No. Anshutz Exploration Corp. v. Town of Dryden, et al., No. 2011-0902 (N.Y. Sup. Ct., Tompkins County Sept. 16, 2011); Cooperstown Holstein Corp. v. Town of Middlefield, No. 2011-0930 (N.Y. Sup. Ct., Ostego County Sept. 15, 2011); Range Resources-Appalachia, LLC, Notice of Challenge of Validity of Ordinance No. 5-2010 Pursuant to 53 P.S. § 1091.1, before the Zoning Hearing Board of South Fayette Township, Allegheny County, PA (Aug. 16, 2011). 103 Order, Northeast Natural Energy v. City of Morgantown, W.V., No. 11-c-411, at 9-10 (Court Aug. 12, 2011). 104 Morgantown, W.V., Business & Taxation Code § 721.01 (June 21, 2011) (copy on file with author). 105 See Verified Complaint ¶¶ 4-5, Northeast Natural Energy v. City of Morgantown, W.V., No. 11-c-411 (Court June 23, 2011). 106 Id. at ¶ 37.

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protection.107 On the other hand, Morgantown contended that it was authorized to enact the ban under West Virginia’s “Home Rule” provisions by characterizing horizontal drilling and hydraulic fracturing as a nuisance.108

On motion for summary judgment, the court acknowledged that the state legislature’s clear purpose in establishing the WVDEP was to “consolidate environmental regulatory programs in a single state 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.”109 The court further acknowledged that under West Virginia’s oil and gas regulatory scheme, “it is within the sole discretion of the WVDEP to perform all duties as related to the exploration, development, production, storage and recovery of this State’s oil and gas.”110 Unable to identify a “Home Rule” exception within the WVDEP’s “comprehensive” regulatory scheme, the court concluded that West Virginia law preempted the Morgantown ban.111 Accordingly, the court entered summary judgment in favor of Northeast.112

The outcome in Northeast is significant in that many states have vested the authority to oversee development of natural resources in regulatory bodies similar to that of the WVDEP. The scope of the Northeast ruling remains unclear, however, and the City of Morgantown is already moving toward enacting a restrictive zoning ordinance that could preclude hydraulic fracturing and horizontal drilling in 98-99% of the city limits.113 The ordinance is not as restrictive as the overturned prohibition, in that residents can appeal for a zoning change in a particular area; the ordinance would also impose noise, fencing, site remediation, and road maintenance requirements.114 The Morgantown response demonstrates that even a significant litigation victory in overturning a regulation may offer only limited practical benefits, at least in the short term, as courts continue to grapple with novel legal issues in their respective jurisdictions.

[b] New York

New York’s localities have fared better in defending regulations or prohibitions on hydraulic fracturing. In two cases decided earlier this year, Anschutz Exploration Corp. v. Town of Dryden and Cooperstown Holstein Corp. v. Town of Middlefield, New York courts upheld the challenged local regulations against challenges from companies hoping to develop shale resources.115 A similar case has been filed this year and is currently pending.116 Both

107 See id. at ¶¶ 49-57. 108 See Order, at 8. 109 Id. at 6 (quoting W.Va. Code § 22-1-1(b)(2)-(3) (1994)). 110 Id. (citing W.Va. Code § 22-6-2 (c)(12) (1994)). 111 See id. at 9. 112 See id. 113 “Morgantown Drilling Regulations Move Forward,” Metro News, June 6, 2012, available at http://www.wvmetronews.com/index.cfm?func=displayfullstory&storyid=53109&type= (last accessed September 6, 2012). 114 Id. 115 Cooperstown Holstein Corp. v. Town of Middlefield, 2012 N.Y.Misc. LEXIS 1420 (N.Y. Sup. Ct., Otsego County, Feb. 24, 2012); Anschutz Exploration Corp. v. Town of Dryden, 940 N.Y.S.2d 458 (N.Y. Sup. Ct., Cortland County, Feb. 21, 2012). 116 Jeffrey v. Ryan, No. 2012-001254 (N.Y. Sup. Ct., Broome County May 30, 2012).

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regulations at issue were similar, in that they completely prohibited oil and gas exploration and production.

The Town of Dryden passed a zoning ordinance on August 2, 2011, prohibiting “all activities related to the exploration for, and production or storage of, natural gas and petroleum.117 The plaintiff, Anschutz, owned gas leases covering over one-third of the town’s area.118 Anschutz argued that this zoning ordinance was preempted either because it was expressly conflicted by the state Oil, Gas and Solution Mining Law (OGSML) or that it conflicted with the OGSML. The OGSML only preempted local laws “relating to the regulation of the oil, gas and solution mining industries,” and the court concluded preemption applied to regulations relating to “operations” and that zoning ordinances regulating land use were not preempted.119 Further, the court concluded that the ordinance was not preempted because of any conflict with the OGSML.120

Similarly, the Town of Middlefield enacted a complete ban on oil, gas or solution mining and drilling on June 28, 2011.121 The plaintiff, Cooperstown, argued that the state Environmental Conservation Law preempted this local ordinance. The court rejected Cooperstown’s challenge, holding that the ECL expressly stated that it did not affect localities’ ability to enact land use regulations, and that the ordinance at issue was such a land use regulation.122

[c] Conclusions

Other localities may enact prohibitions on hydraulic fracturing, or oil and gas development generally, given the success that municipalities have had in defending such prohibitions in New York. As illustrated by the dichotomy between West Virginia and New York, preemption is heavily dependent upon each state’s specific allocation of powers between the state government and localities. It is therefore difficult to predict how the courts in a particular state would treat a similar regulation if challenged.

[4] Butler v. Powers – Ownership of Shale Gas in Pennsylvania

The presence of extensive shale resources in non-traditional oil and gas producing states will result in many courts deciding cases that present important questions of first impression on issues important to hydraulic fracturing. One such case is Butler v. Charles Powers Estate, et al., and it warrants some discussion here in that it could have a significant impact on traditional notions of shale gas ownership in the state.

The primary issue in Butler is whether the language “minerals and Petroleum Oils” as contained in a reservation carved out of Plaintiffs’ 1881 deed, included natural gas trapped in

117 Anschutz Exploration Corp., 940 N.Y.S.2d 458, 464. 118 Id. at 460. 119 Id. at 466-68. 120 Id. at 468-71 121 Cooperstown Holstein Corp. v. Town of Middlefield, 943 N.Y.S.2d 722, 723 (N.Y. Sup. Ct., Otsego County, Feb. 24, 2012). 122 Id. at 729-30.

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Marcellus shale underlying the plaintiffs’ land.123 At the trial court level, the court relied on the Dunham Rule.124 That rule states that a deed or instrument reserving or conveying “minerals” without any reference to oil or gas creates a rebuttable presumption that that the grantor did not intend for the “minerals” to include oil or gas.125 On that basis, the trial court ruled that the language in the reservation did not include Marcellus shale gas.126 Shortly thereafter, the defendant heirs of the reservation’s original beneficiary appealed to the Pennsylvania Superior Court.

On appeal, the appellants urged the Superior Court to treat gas contained in Marcellus shale in the same manner that Pennsylvania courts have treated gas contained in coal.127 In so doing, the appellants cited to U.S. Steel Corp. v. Hoge in which the Pennsylvania Supreme Court held that whatever gas is present in coal belongs to the owner of the coal.128 Under such an approach, any failure to expressly reserve gas under the Dunham Rule would be immaterial to the extent that the language in the deed is sufficient to create ownership of the shale containing the gas at issue. On September 7, 2011, the Superior Court issued an opinion stating that it disagreed with the trial court’s decision. In doing so, the Superior Court held that the Dunham Rule did not end the analysis of the ownership of the Marcellus shale gas and that a more sufficient understanding of the issues was necessary, including whether: “(1) Marcellus shale constitutes a ‘mineral’; (2) Marcellus shale gas constitutes the type of conventional natural gas contemplated in Dunham … ; and (3) whether Marcellus shale is similar to coal to the extent that whoever owns the shale, owns the shale gas.”129 For those reasons, the Superior Court ordered the case remanded to the trial court to allow Appellants the opportunity to establish that Marcellus shale gas is an unconventional gas that, like coalbed methane, defies categorization as a natural gas.130

Before the trial court took up the case again, the plaintiffs sought review from the Pennsylvania Supreme Court, and the court agreed to review the case on April 3, 2012.131 A number of amicus briefs have been filed, and oral arguments are expected in the next several months.

Though some would attempt to ascribe greater significance to the Superior Court’s decision, for now, it is clear only that the Superior Court felt that the defendants should be afforded the opportunity to present their argument that the Dunham rule may not apply to shale gas in Pennsylvania. The disposition of the case by the Pennsylvania Supreme Court, however, could have significant effects. And regardless of the disposition, resolution of the legal issues will help provide certainty for property owners and oil and gas operators. The Supreme Court’s prompt acceptance of the case also indicates that the court is sensitive to the importance of

123 See Butler v. Charles Powers Estate, et al., 29 A.3d 35, 37, 38 (Pa. Super. Ct., 2011). 124 See Dunham v. Kirkpatrick, 101 Pa. 36 (1882). 125 See Butler, 29 A.3d at 43. 126 See id. at 38. 127 See id. at 40. 128 See id. 129 Id. at 43. 130 See id. 131 Butler v. Charles Powers Estate, et al., No. 760 MAL 2011, 2012 WL 1087928 (Pa. Apr. 3, 2012).

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resolving issues pertinent to shale development.132 A decision may not be rendered for some time, however, as the Pennsylvania Supreme Court only recently decided T.W. Phillips Gas & Oil v. Jedlicka, another important case that was argued two years previously.133 The court held in that case that the determination of whether a well is producing paying quantities is determined with reference to the operator’s good-faith judgment.134

[5] Future Possibilities

If history teaches us anything, as long as shale gas development remains profitable, the energy industry will continue to develop our country’s shale gas resources. And, as long as there is ongoing development, there will be its opponents who come to the courts seeking redress as concerned citizens, environmental organizations, governments, or those claiming injury. Thus, the future will likely bring much of the same with respect to the types of shale-related litigation discussed herein. But, that is not to say those are the only types of cases we are likely to see.

Many of the states at the heart of the current boom in natural gas development are not what, many would consider, “traditional” oil and gas producing states. As such, these states lack the benefit of precedent when dealing with the many issues that arise in the context of shale gas development. It is possible and even likely, therefore, that many “well-settled” issues in traditional oil and gas producing jurisdictions will be issues of first impression for courts in states that do not.

For example, consider the Butler case discussed above. In a very real sense, that case is nothing more than a dispute over mineral ownership. And, though the Dunham case arguably supplies precedent from which the Butler courts can draw upon, that case is over one hundred years old with subsequent history that is considerably less developed than would be expected in traditional oil and gas jurisdictions. Under such circumstances there is an added level of unpredictability of which potential litigants should be aware. That being said, one would expect courts considering questions of first impression to look to those jurisdictions with more developed precedent for guidance. As such, when it comes to the more fundamental issues any unpredictability that might exist as to how such courts will rule can be mitigated by looking to how other more traditional oil and gas jurisdictions have dealt with those same issues. Where a party must be careful, however, is in litigating the more nuanced issues.

Take the issue of whether “at the wellhead” language implies the deductibility of post-production costs. In most traditional oil and gas jurisdictions that issue is fairly well settled, with states such as Texas, Louisiana, and Mississippi falling within the category of those that imply such deductions where “at the wellhead” language is employed.135 The answers are not as straightforward, however, when one takes the issue a step further and tries to determine whether those same costs are deductible where “at the wellhead” is accompanied by contradictory “no-deduct” language. For example, in Texas, there is clear Texas Supreme Court precedent stating that “at the wellhead” language trumps any contradictory “no-deduct” provisions. Louisiana

132 Thomas J. Farnan, “‘Mineral’ Definition Case Could Have Big Impact,” 245 The Legal Intelligence 94, (Phil. May 15, 2012). 133 T.W. Phillips Gas & Oil Co. v. Jedlicka, 42 A.3d 261 (Pa. 2012). 134 Id. at 263. 135 See Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118, 121 (Tex. 1996).

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courts, on the other hand, have indicated that express “no-deduct” language trumps any implications drawn elsewhere in a written instrument.136 And lastly, Mississippi courts have yet to address the issue although cases on the periphery suggest that it is more likely that “no-deduct” language would govern.137 Given the differences that exist amongst traditional oil and gas jurisdictions, one would expect even less predictability when litigating before a court that has yet to reach the issue at its more fundamental level.

Thus, while no can know exactly what the future will bring, potential litigants would be wise to consider their operations in jurisdictions with less developed oil and gas precedent and proceed with an added measure of care; in particularly when dealing with the more nuanced issues that arise in the context of shale gas production.

136 See Columbine II Ltd. Partnership v. Energen Resources Corp., 129 Fed. Appx. 119, 122-23 (5th Cir. 2005) (applying Louisiana law); Merritt v. Southwestern Elec. Power Co., 499 So.2d 210, 214 (La. Ct. App. 1986). 137 See Pursue Energy Corp. v. Abernathy, 77 So.3d 1094, 1099 (Miss. Oct. 13, 2011) (following Piney Woods Country Life Sch. v. Shell Oil Co., 726 F.2d 225, 331 (5th Cir. 1984)); see also Williamson v. Elf Aquitaine, Inc., 138 F.3d 546, 549-550 (5th Cir. 1998) (“[U]nder Mississippi law … implied covenants are inapplicable when a contract contains express provisions on that particular issue.”).

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§ 3.01 Regulatory Developments

[1] Overview

In the area of regulation, it is difficult, if not impossible, to separate shale development from hydraulic fracturing. The vast majority of regulations that impact shale development in the United States involve efforts by federal, state, and local governments to regulate the use of hydraulic fracturing. Currently, the majority of the regulations targeting hydraulic fracturing and shale development are enacted and implemented at the state level. However, the EPA is currently studying the effects of hydraulic fracturing on the environment and the publication of this study may motivate Congress to enact additional legislation that would give greater authority to the EPA to regulate hydraulic fracturing. This study will have significant effects for federal and state regulations alike. Additionally, the EPA has enacted some regulations under its existing statutory authority that impact hydraulic fracturing and it will likely enact additional regulations in the near future governing chemical disclosure and disposal of flowback water. At the state and local level, key trends include aggregation of facilities for state air emissions standards, more restrictive water withdrawal standards, additional siting restrictions in a variety of areas, greater involvement by localities in hydraulic fracturing regulation, and an increase in chemical disclosure requirements.

[2] Federal Regulations

The most significant environmental concerns arising from hydraulic fracturing center on the potential for groundwater contamination, and the EPA is currently studying these effects.138 Additionally, the EPA retains the authority to regulate hydraulic fracturing operations that utilize diesel fuels.139 The EPA has not yet promulgated any rules under this authority, but has issued draft guidance for federal permit writers issuing permits for hydraulic fracturing operations that utilize diesel fuels.140 The public comment period on this draft guidance closed on August 23, 2012. Finally, the EPA has recently announced its intention to develop rules that would require companies to disclose chemicals and additives used in hydraulic fracturing.141

In addition to groundwater, hydraulic fracturing has raised concerns about both emissions of chemicals into the air during flowback and the disposal of flowback wastewater.142 The EPA has authority to regulate the emissions of all natural gas wells into the atmosphere under the Clean Air Act (CAA) and the EPA has issued New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) that specifically regulate

138 EPA, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, EPA/600/R-11/122, (Nov. 2011), available at http://water.epa/gov/type/groundwater/uic/class2/hydraulicfracturing/upload/hf_study_plan_11024_final_508.pdf. 139 Safe Drinking Water Act, § 1421(d)(1)(B)(ii); 42 U.S.C. § 300h(d)(1)(B)(ii). 140 Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels—Draft: Underground Injection Control Program Guidance #84, EPA 816-R-12-004 (May 4, 2012) (“Draft Guidance”), http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/upload/hfdieselfuelsguidance508.pdf. 141 Letter from Stephen A. Owens, Assistant Adm’r, Office of Chem. Safety and Pollution Prevention, EPA, to Deborah Goldberg, Earthjustice (Nov. 23, 2011) (on file with author). 142 EPA, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources 81-82.

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hydraulic fracturing operations.143 In addition to its authority under the CAA, the EPA also has authority, under the Clean Water Act (CWA) to regulate the discharge of flowback waters after hydraulic fracturing is complete.144 The EPA is currently studying treatment methods for these waters and will soon propose new treatment standards for wastewater produced in hydraulic fracturing operations.145

Further, the Bureau of Land Management (BLM) recently released proposed rules regulating hydraulic fracturing practices and requiring public disclosure of chemicals used in hydraulic fracturing on public and tribal land.146 The comment period for the proposed rules closed on September 10, 2012.147 On January 18, 2013, however, BLM withdrew the proposed rules, and it will release new proposed rules in April.148

[a] Possible regulation under the Safe Drinking Water Act

The Safe Drinking Water Act (SDWA) provides the EPA with authority to enact regulations to protect groundwater, but the Energy Policy Act of 2005, excluded “underground injection of fluids or propping agents (other than diesel fuels) pursuant to hydraulic fracturing operations” from regulation.149 Since 2005, environmental groups have urged Congress to enact the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act, legislation that has been introduced in both houses of Congress that would again amend the SDWA, this time to remove the exclusion of hydraulic fracturing from regulation.150 Although the legislation has not progressed in either house, Congress has requested that the EPA study the effects of hydraulic fracturing on drinking water sources and publish its findings.151 In 2011, the EPA published its final plan for a comprehensive study of hydraulic fracturing,152 issued a second round of important disclosure requests as part of its study, and completed a significant investigation at a hydraulic fracturing site in Wyoming.153 In March 2012, EPA announced its plan to resample two monitoring wells in Pavillion.154 Additionally, on May 4, 2012 the EPA issued draft

143 Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Aire Pollutants Reviews, U.S. Environmental Protection Agency (Apr. 17, 2012) (“Rule”), http://www.epa.gov/airquality/oilandgas/pdfs/20120417finalrule.pdf. 144 40 C.F.R. § 403.5. 145 76 Fed. Reg. 66,286 (Oct. 26, 2011). 146 Oil and Gas; Well Stimulation, Including Hydraulic Fracturing, on Federal and Indian Land, 77 Fed. Reg. 27, 691 (proposed May 4, 2012) (to be codified at 43 C.F.R. pt. 3160). 147 77 Fed. Reg. 38,024 (June 26, 2012). 148 Nick Snow, “BLM Pulls Proposed Fracing Rules, Works on New Version,” Oil and Gas Journal (Jan. 21, 2013), http://www.ogj.com/articles/2013/01/blm-pulls-proposed-fracing-rules--works-on-new-version.html. 149 Energy Policy Act of 2005, § 322(1); Safe Drinking Water Act § 1421(d), 42 U.S.C. § 300h(d). 150 Fracturing Responsibility and Awareness of Chemicals (FRAC) Act of 2011, H.R. 1084 (March 15, 2011), available at http://www.govtrack.us/congress/billtext.xpd?bill=h112-1084; Fracturing Responsibility and Awareness of Chemicals (FRAC) Act of 2011, S. 587 (March 15, 2011), available at http://www.govtrack.us/congress/billtext.xpd?bill=s12-587. 151 EPA, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources 1. 152 Id. 153 EPA, Draft Investigation of Ground Water Contamination near Pavillion, Wyoming. 154 EPA, Statement of Pavillion, Wyoming groundwater investigation (March 8, 2012), http://yosemite.epa.gov/opa/admpress.nsf/d0cf6618525a9efb8525739003fb69d/17640d44f5be4cef82579bb006432de!opendocument.

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guidelines applicable to hydraulic fracturing operations that use diesel fuels.155 And in December 2012, EPA released a progress report on its comprehensive study of the effects of hydraulic fracturing on groundwater and drinking water.156

[i] EPA study plan

The EPA released the final plan for the study in November of 2011; the plan included five principal questions addressing different topical areas, with several subsidiary questions for each. The principal issues to be addressed in the study are:

1. What are the potential impacts of large volume water withdrawals from ground and surface waters on drinking water resources?157

2. What are the possible impacts of surface spills on or near well pads of hydraulic fracturing fluids on drinking water resources?158

3. What are the possible impacts of the injection and fracturing process on drinking water resources?159

4. What are the possible impacts of surface spills on or near well pads or flowback and produced water on drinking water resources?160

5. What are the possible impacts of inadequate treatment of hydraulic fracturing wastewaters on drinking resources?161

155 Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels—Draft: Underground Injection Control Program Guidance #84. 156 EPA, Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources: Progress Report, EPA 601/R-12/011, Dec. 2012. 157 The subsidiary questions were: (1) How much water is used in hydraulic fracturing operations, and what are the sources of this water?; (2) How might water withdrawals affect short- and long-term water availability in areas with hydraulic fracturing activity?; and (3) What are the possible impacts of water withdrawals for hydraulic fracturing operations on local water quality? EPA, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources 22-27. 158 The subsidiary questions were: (1) What is currently known about the frequency, severity, and causes of spills of hydraulic fracturing fluids and additives; (2) What are the identities and volumes of chemicals used in hydraulic fracturing fluids, and how might this composition vary at a given site and across the country; (3) What are the chemical, physical, and toxicological properties of hydraulic fracturing chemical additives; and (4) If spills occur, how might hydraulic fracturing chemical additives contaminate drinking water resources? Id. at 28-33. 159 The subsidiary questions were: (1) How effective are current well construction practices at containing gases and fluids before, during, and after fracturing?; (2) Can subsurface migration of fluids or gases to drinking water resources occur, and what local geologic or man-made features may allow this?; (3) How might hydraulic fracturing fluids change the fate and transport of substances in the subsurface through geochemical interactions?; and (4) What are the chemical, physical, and toxicological properties of substances in the subsurface that may be released by hydraulic fracturing operations? Id. at 34-42. 160 The subsidiary questions were: (1) What is currently known about the frequency, severity, and causes of spills of flowback and produced water?; (2) What is the composition of hydraulic fracturing wastewaters, and what factors might influence this composition?; (3) What are the chemical, physical, and toxicological properties of hydraulic fracturing wastewater constituents?; and (4) If spills occur, how might hydraulic fracturing wastewaters contaminate drinking water resources? Id. at 42-48.

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To complete this study, the final plan indicated that the EPA would analyze existing data (provided by companies engaging in hydraulic fracturing, government agencies, and other entities), complete selected case studies (involving sampling at sites and analysis of samples), model and analyze certain scenarios, and undergo laboratory and toxicological studies.162 The EPA released an initial progress report in December 2012, which largely restated the objectives and methodology set forth in the study plan, without offering any new data or initial assessment.163 The initial Study Plan appeared to indicate that some research findings and initial conclusions were intended to be disclosed in the progress report; however, no such conclusions were included.164 A final draft report will be released in 2014 for public comment and peer review, which will include an assessment of existing data, laboratory studies, scenario evaluations, toxicological assessments, and results of case studies.165 The study will have significant importance, both in framing the safety of hydraulic fracturing for Congress, as it considers the FRAC Act, and in providing impetus for additional regulation by the EPA under its existing statutory authority and for legislation and regulation at the state and local level.

[ii] Pavillion, Wyoming ground water contamination investigation

In March 2012, the EPA announced its intention to conduct further sampling of the deep monitoring wells drilled for the Agency’s investigation of groundwater contamination in Pavillion, Wyoming.166 The EPA released its initial findings from its previous investigation in 2011.167 Complaints from local residents about groundwater in the area prompted the investigation, with the agency sampling water between 2009 and 2011.168 Although this investigation is not a part of the larger study commissioned by Congress to examine the potential effects of hydraulic fracturing on groundwater and was focused only on determining whether groundwater contamination existed in that area, the investigation does provide important insights into the EPA’s methodology and views on hydraulic fracturing. The initial findings from the Pavillion investigation offer significantly more detailed information about the EPA’s approach, 161 The subsidiary questions were: (1) What are the common treatment and disposal methods for hydraulic fracturing wastewaters, and where are these methods practiced?; (2) How effective are conventional POTWs and commercial treatment systems in removing organic and inorganic contaminants of concern in hydraulic fracturing wastewaters?; and (3) What are the potential impacts from surface water disposal of treated hydraulic fracturing wastewater on drinking water treatment facilities? Id. at 48-53. 162 Id. at 56-72. The seven case study sites are located in DeSoto Parish, LA; Washington County, PA (two sites); Dunn County, ND; Bradford and Susquehanna Counties, PA; and the Raton Basin in Colorado. One of the Washington County, PA sites and the DeSoto Parish, LA sites will be subjects in the prospective studies, which will include an analysis by the EPA of environmental conditions before and after hydraulic fracturing operations. “Case Studies,” EPA’s Study of Hydraulic Fracturing and Its Potential Impact on Drinking Water Resources, http://www.epa. gov/hfstudy/index.html#august2011. As described below, the lack of baseline data in the Pavillion, WY investigation was a significant shortcoming, and the prospective studies will be especially important because they will enable the EPA to compare baseline data to the samples collected after hydraulic fracturing is completed. 163 EPA, Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources Progress Report, December 2012, http://www.epa.gov/hfstudy/. 164 EPA, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources 7 (“A peer-reviewed study report providing up-to-date research results will be released to the public in 2012.”). 165EPA Press Release, EPA Releases Update on Ongoing Hydraulic Fracturing Study, Dec. 21, 2012. 166 EPA, Statement of Pavillion, Wyoming groundwater investigation (March 8, 2012), http://yosemite.epa.gov/opa/admpress.nsf/d0cf6618525a9efb85257359003fb69d/17640d44f5be4cef852579bb006432de!opendocument. 167 EPA, Draft Investigation of Ground Water Contamination near Pavillion, Wyoming. 168 Id. at 1.

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aspects of which will likely be replicated to some extent in the EPA’s case studies for the larger study on hydraulic fracturing.

On that point, the methodology used and inferences drawn regarding potential contamination originating from the wellbore were relatively complex, and, although the EPA concluded that contamination had occurred, its conclusion was perhaps slightly more tentative, as compared to the EPA’s analysis of possible groundwater contamination in the area stemming from the storage of wastewater.169 Relying on the use of reaction path modeling, inorganic chemistry atypical for the area, high concentrations of methane, and the presence of certain synthetic organic compounds, including tert-buyl alcohol, the EPA concluded that hydraulic fracturing had likely introduced some contamination into the groundwater.170 In reaching this conclusion, the EPA also considered alternative explanations for the presence of the chemicals and other anomalies, but concluded that hydraulic fracturing was the most likely cause of the apparent contamination.171

The key shortcoming of the Pavillion study was the lack of baseline data against which the EPA could compare its samplings, a fact that the EPA noted in its conclusions.172 A number of commentators have also raised other questions about the study’s conclusions, including the failure of the EPA to consider the historic presence of many chemicals in the area’s groundwater and use of “legacy pits” in the area to store wastewater many years earlier, as well as the fact that the drilling in the Pavillion area was much shallower than is typical in hydraulic fracturing operations.173 Looking ahead to the broader study to be completed in 2014, two of the EPA’s case studies will include the collection of baseline data prior to hydraulic fracturing, which will be compared with samples collected after hydraulic fracturing is completed in those areas.174 Another important facet of the study will be the geological diversity of the sites selected for case studies.175 Although the EPA did not include any formal recommendations in its initial report on Pavillion, the agency noted that the “investigation supports the recommendations made by the U.S. Department of Energy Panel … on the need for the collection of baseline data, greater transparency on chemical composition of hydraulic fracturing fluids, and greater emphasis on well construction and integrity requirements and testing.”176 The Pavillion study is also noteworthy in that the EPA pointed to the Comprehensive Environmental Response Compensation and Liability Act (“CERCLA” or “Superfund”) as statutory authority for the investigation.177 Although CERCLA precludes the EPA from ordering remediation for

169 Id. at 33-39. 170 Id. 171 Id. 172 EPA, Draft Investigation of Ground Water Contamination near Pavillion, Wyoming 39. 173 Editorial, The EPA’s Fracking Scare, Wall Street Journal, Dec. 20, 2011, http://online. wsj.com/ article/SB10001424052970204026804577098112387490158.html. 174 EPA, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources 66-67. 175 Id. at 59. 176 EPA, Draft Investigation of Ground Water Contamination near Pavillion 39. 177 Id. at 1.

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contamination caused by crude oil and natural gas,178 the EPA may still be able to order remediation for contamination caused by hydraulic fracturing fluids.179

To clarify questions about the initial monitoring results, the EPA, in cooperation with the U.S. Geological Survey, the Tribes180, and the State of Wyoming, re-sampled two monitoring wells the Agency installed in the Pavillion area.181 The EPA collaborated with the State and other stakeholders in designing the sampling methodology, the quality assurance plan, and other features of this phase of testing.182 Sample results were released September 26, 2012.183 To provide additional time for the public to review and comment on the new data, EPA extended the public comment period on the draft report of initial study through September 30, 2013.184

[iii] Dimock, Pennsylvania groundwater contamination investigation

On July 25, 2012, EPA announced that it had completed its sampling of private drinking water wells in Dimock, PA.185 Based on the outcome of the sampling, the EPA determined that no additional action by the Agency was required.186

The EPA took steps to sample water in the Dimock area following requests by the town’s residents.187 Between January and June 2012, the Agency sampled private drinking water wells serving 64 homes, including two rounds of sampling at four wells where EPA delivered temporary water supplies as a precautionary step in response to prior data indicating the well water contained levels of contaminants that pose a health concern.188 EPA found naturally occurring hazardous substances in well water at five homes at levels that could present a health concern.189 In all cases the residents have now or will have their own treatment systems that can reduce concentration of those hazardous substances to acceptable levels at the tap.190 The EPA has no further plans to conduct additional drinking water sampling in Dimock.191

178 42 U.S.C. § 9601(14). 179 Rebecca Jo Reser & David T. Ritter, State and Federal Legislation and Regulation of Hydraulic Fracturing, The Advocate 32-33 (Winter 2011). 180 EPA, Statement on Pavillion, Wyoming groundwater investigation. The Tribes refer to the Northern Arapaho and Eastern Shoshone Tribes. 181 See id.; see also EPA, Update on 2012 sampling activity (June, 2012), http://www.epa.gov/region8/superfund/wy/pavillion/. 182 Id. 183 See, Groundwater Investigation: Pavillion, http://www.epa.gov/region8/superfund/wy/pavillion/. 184 Id. 185 EPA, EPA Completes Drinking Water Sampling in Dimock, Pa (July 25, 2012), http://yosemite.epa.gov/opa/admpress.nsf/0/1A6E49D193E1007585257A46005B61AD. 186 Id. 187 Id. 188 Id. 189 Id. 190 Id. 191 Id.

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[iv] Disclosure requests

As part of its information-gathering effort for its larger study on hydraulic fracturing, the EPA sought voluntary disclosures from a number of companies with hydraulic fracturing operations.192 The first round of requests were issued in September of 2010 on companies that provided hydraulic fracturing fluid services to well operators, and sought significant information as to the chemical components in the hydraulic fracturing fluids, data and studies related to the human health and environmental impacts of materials used, practices and procedures regarding hydraulic fracturing operations including the modification of fluids at the well sites, and identification of all individuals and entities who used hydraulic fracturing fluid services and sites where they were used.193

The EPA made a second round of requests in August of 2011, this time to the operators of a number of wells that utilized the hydraulic fracturing services provided by the companies who were the subject of the first round of disclosures.194 The information requested in this round was significantly broader, including geological maps of areas where wells were located, daily records relating to drilling, results from any water sampling at the well sites, volume and final disposition of flowback and produced water, results of any studies of flowback and produced water, information about the acquisition of base fluid used for fracture stimulation, estimate of fracture growth and propagation prior to hydraulic fracturing, fracturing stimulation pumping plan, post-fracture data reports, seismic data, and reports regarding any spills at the well.195

[v] Regulation of fluids using diesel fuel

Although much of the EPA’s efforts to regulate hydraulic fracturing will depend upon the outcome of the study, EPA already has the ability to regulate hydraulic fracturing when diesel fuel is among the chemicals used by operators.196 Despite this power, the agency has not yet adopted specific regulations. Instead, the EPA has classified diesel fuel as a Class II Underground Injection Control (UIC) substance.197 This is the classification generally applicable to oil and natural gas-related injection and requires that a permit be obtained prior to the underground injection of covered substances.198

Under this classification, the EPA has released a draft guidance document explaining how federal permit writers should adapt existing UIC requirements for Class II wells to hydraulic diesel fuel.199 The draft guidance outlines the definition of diesel fuels and provides recommendations on how permit writers should implement UIC permitting requirements related

192 EPA, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources Appendix D, 114-16. 193 Id. 194 Id. at 116-18. 195 Id. 196 Safe Drinking Water Act, § 1421(d)(1)(B)(ii); 42 U.S.C. § 300h(d)(1)(B)(ii). 197 EPA, Underground Injection Control 101 Presentation, available at http://water.epa.gov/type/ groundwater/uic/class2/hydraulicfracturing/upload/uic_101_webinar_presentation.pdf. 198 Id. 199 Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels—Draft: Underground Injection Control Program Guidance #84, EPA 816-R-12-004 (May 4, 2012) (“Draft Guidance”), http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/upload/hfdieselfuelsguidance508.pdf.

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to permit duration and well closure, permit application and reviw, area of review (AoR), and well construction, including mechanical integrity testing, financial responsibility, and public notification.200

The EPA proposed to define diesel fuels by reference to six chemical abstract services registry number.201 The Agency sought comments on the alternatives as well as on whether a de minimis level of diesel fuel constituents should be included.202 EPA also sought information on specific permitting and operational issues, including: (i) Diesel fuels usage information; (ii) Permit duration and well closure; (iii) AoR; (iv) Information Submitted with the Permit Application; and, (v) Monitoring.203 The public comment period on EPA’s draft guidance closed August 23, 2012.204

The guidance will not have the effect of law.205 Still the concern for industry is that the Class II UIC requirements will become de facto standards for all hydraulic fracturing.206 Also controversial is EPA’s decision to proceed with guidance rather than rulemaking.207 Meanwhile, environmentalists commented that the guidance is inadequate and are calling on the Agency to ban all use of diesel in fracturing fluids.208

[b] Possible mandatory disclosure under Toxic Substances Control Act (TSCA)

Although the SDWA may be the most important statute for federal regulatory authority pertinent to hydraulic fracturing, other statutes provide the EPA with additional avenues of regulation. In response to petitions filed by environmental advocacy groups, the EPA is preparing to require companies engaged in hydraulic fracturing to publicly disclose certain information about the chemicals and additives used in the process.209 The Toxic Substance Control Act (TSCA) provides the rulemaking authority for the EPA to require such disclosures, and the agency is planning to convene a stakeholder process that would emphasize the use of existing information and the avoidance of unnecessary burdens on industry.210 The EPA announced its intentions in a letter to several environmental advocacy groups, but it did not

200 Id. at 1. 201 Id. at 9-11. 202 Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels—Draft: Underground Injection Control Program Guidance #84, EPA, Request for Comment on Draft Comment Document, 77 Fed, Reg. 27451 (May 10, 2012). 203 Id. 204 Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels-Draft, EPA, Extension of Comment Period, 77 Fed. Reg. 40354 (July 9, 2012). 205 Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels—Draft: Underground Injection Control Program Guidance #84, at 3. 206 Roger W. Patrick, US Environmental Protection Agency Issues Draft Guidance on Underground Injection Control Permits for Hydraulic Fracturing Using Diesel Fuel, Martindale-Hubbell (May 10, 2012), http://www.martindale.com/environmental-law/article_Mayer-Brown-LLP_1509524.htm. 207 Id. 208 Id. See also Nick Snow, EPA Releases Draft Permitting Guidance for Diesel Fuel in Fracking, Oil & Gas Journal (May 14, 2012), http://www.ogj.com/articles/2012/05/epa-releases-draft-permitting-guidance-for-diesel-fuel-in-fracing.html. 209 Letter from Stephen A. Owens, Assistant Adm’r, Office of Chem. Safety and Pollution Prevention, EPA, to Deborah Goldberg, Earthjustice, Nov. 23, 2011. 210 Id.

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specify any timetable for the rulemaking and it is unclear what information will be subject to the disclosure requirements.211 In a possible sign of the EPA’s focus on hydraulic fracturing, the environmental groups had petitioned the EPA to impose disclosure requirements on all chemicals and additives used in any way for oil and natural gas exploration and production, but the EPA narrowed the scope of the process to substances used in hydraulic fracturing.212 The EPA also rejected the petitioners’ request to impose toxicity testing requirements on chemicals used in oil and gas production, noting that the petitioners had not established the need for such data.213

The EPA’s announcement of its plans to impose a disclosure regime further indicates its interest in regulating hydraulic fracturing more closely. Given the EPA’s stated emphasis on minimizing burdens to the industry, it would seem likely that the disclosure requirements will not significantly differ from the disclosure requirements that many states have imposed, but this is by no means certain. The precise scope of the disclosure rules is likely to be contentious, and a critical issue will be the EPA’s treatment of trade secrets and other proprietary information. As discussed below, this information is subject to various types of safeguards under state disclosure requirements, ranging from significant safeguards to no protection at all. Additionally, disclosure requirements that the Department of the Interior’s Bureau of Land Management (“BLM”) has proposed for hydraulic fracturing on federal lands include trade secret protections, showing some degree of concern at the federal level for maintaining the confidentiality of this information where possible.214 The BLM proposed rules regulating well stimulation and hydraulic fracturing activities on federal and tribal land were proposed on May 4, 2012 and the comment period closed September 10, 2012. Given the EPA’s emphasis on developing a comprehensive body of information on hydraulic fracturing, however, the agency may require disclosure of significant information beyond the composition of chemicals used in fracturing fluids including studies and reports on the safety of those chemicals and their impact on groundwater during the hydraulic fracturing process.

[c] New emissions regulations under the Clean Air Act

In April 2012, under the Clean Air Act (CAA), the EPA issued a final rule addressing the New Source Performance Standard (NSPS) targeted at volatile organic compound and sulfur dioxide emissions215 and two expansions of National Emissions Standards for Hazardous Air Pollutants (NESHAP), targeted at the emissions of air toxics.216 The Rule governs all upstream oil and gas facilities and midstream gas facilities, and has particular application to hydraulic fracturing operations.217 The NSPS standards apply to facilities that began construction or

211 Id. 212 Id. 213 Id. 214 Statement of Ken Salazar, Sec’y of the Interior, Before the Comm. on Natural Res. U.S. House of Reps., “The Future of U.S. Oil and Natural Gas Development on Federal Lands and Waters,” November 16, 2011, available at, http://naturalresources.house.gov/UploadedFiles/Salazar Testimony11.16.11.pdf, at 4 (“[The Bureau of Land Management] is considering revisions to its current regulations that would address disclosure of the chemicals used in hydraulic fracturing process with necessary provisions related to protecting trade secrets.”). 215 The final rules are also expected to reduce methane emissions. 216 Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews, U.S. Environmental Protection Agency (Apr. 17, 2012) (“Rule”), http://www.epa.gov/airquality/oilandgas/pdfs/20120417finalrule.pdf. 217 See id. at 280-84 (to be codified at 40 C.F.R. § 60.5365).

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modification after August 23, 2011, the publication date of the proposed rule.218 The facilities subject to the Rule were required to come into compliance 60 days after August 16, 2012 when the final rule was published in the Federal Register.219 Some of the NESHAP provisions, however, have a longer implementation period of three years and 60 days after the date of publication in the Federal Register.220

Notably, the NSPS expressly exempts exploratory wells, delineation wells and non-exploratory, non-delineation “low pressure gas wells”221 from the mandate to employ “reduced emission completion” (REC) technology (also referred to as “green completion”) that minimizes emissions from flowback and maximizes resource recovery.222 Instead, the exempted wells can employ a combustion device.223 The Rule further provides that in situations where using REC technology is “infeasible” the operator may use a completion combustion device to control flowback emissions.224 The Rule provides a relatively long phase-in period—the requirement to employ REC technology will only apply to well completion operations that commence on or after January 1, 2015.225 In addition to the REC standards, the NSPS includes detailed standards for compressors, pneumatic controllers, and storage vessels, as well as for equipment leaks at equipment leaks and sweetening units at onshore natural gas processing plants.226 The Rule does not exempt from compliance periods of startup, shutdown, and malfunction, instead offering a limited affirmative defense for non-compliance during malfunction only where the malfunction was unavoidable, repairs were made expeditiously, excess emissions were minimized to the extent possible, and certain documentation and notification standards were met.227 Finally, the NSPS also includes significant notification requirements,228 but it tries to streamline the notification process.229 For example, operators need only provide EPA with two days’ advance notice, which may be provided by email.230 Moreover, compliance with the state prior notice requirement will satisfy the NSPS’s advance notice requirement.231

In addition to the new NSPS, the EPA has also issued amendments to two NESHAPs, one of which applies to all oil and natural gas production facilities and the other applying to

218 Id. at 280 (to be codified at 40 C.F.R § 60.5376). 219 Id. at 285 (to be codified at 40 C.F.R. § 60.5370). The Rule was expected to be published in the Federal Register in May 2012. However, as in August 2012, the Rule has not been published yet. 220 See, e.g., id. at 424-25, 509 (to be codified at 40 C.F.R. §§ 63.760(f)(7), (9)), 63.1270(d)(3)). 221 Id. at 408 (to be codified at 40 C.F.R. § 60.5430). Whether a well qualifies as a low pressure gas well is determined based on the well’s vertical depth, reservoir pressure, and the flow line pressure at the sales meter, using a prescribed equation. 222 Id. at 285-88 (to be codified at 40 C.F.R. § 60.5375(a)). 223 Id. 224 Id. at 286 (to be codified at 40 C.F.R. § 60.5375(a)(1)). The Rule, however, does not define the term “infeasible.” 225 Id. at 285-88 (to be codified at 40 C.F.R. § 60.5375(a)). 226 Id. at 289, 290, 291-92, 293-94, 295-300, 301 (to be codified at 40 C.F.R. §§ 60.5380(a) (compressors), 60.5385(a) (compressors), 60.5390(b)-(c) (pneumatic controllers), 60.5395(a)-(b) (storage vessels), 60.5400-5402 (equipment leaks), 60.5405(b) (sweetening units)). 227 Id. at 361 (to be codified at 40 C.F.R. § 60.5415(h)). 228 Id. at 385-401 (to be codified at 40 C.F.R. §§ 60.5420-23). 229 See id. at 43. 230 Id. at 386 (to be codified at 40 C.F.R. § 60.5420(a)(2)(i)). 231 Id. (to be codified at 40 C.F.R. § 60.5420(a)(2)(ii)).

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natural gas transmission and storage facilities.232 These standards will set emissions limits for small glycol dehydrators233 at the Maximum Achievable Control Technology (MACT) floor, which existing rules do not govern.234 Even though the proposed amendments contemplated removing the one ton per year benzene compliance option for all glycol dehydrators and require large glycol dehydrators to reduce air toxic emissions by 95% by routing them to a control device, the final rule preserved this option for large glycol dehydrators.235 Additional proposals affect standards for equipment leaks.236 Like the NSPS, the NESHAP regulations also would impose significant monitoring, recordkeeping, and reporting requirements and eliminate the exemption provisions for periods of startup, shutdown, and malfunction, providing only a limited affirmative defense for non-compliance during malfunction periods.237

The Rule has significant economic implications for the industry and the society. EPA estimates the cost to industry of compliance to be approximately $170 million in 2008 dollars.238 The Agency also estimates that the final standards will result in net annual saving of $11 million in 2008 dollars, due to the recovery of salable gas and condensate.239 In addition, EPA values social benefit from the expected reduction in methane emission at $440 million annually starting from 2015.240

[d] Regulation of wastewater under the Clean Water Act

Like the CAA, the Clean Water Act (CWA) imposes regulatory requirements that are relevant to shale development and hydraulic fracturing and the exemption in the SDWA is inapplicable to regulations that may be promulgated under the CWA.241 The CWA governs the disposal of material into water, and the CWA is therefore of importance to the disposal of flowback wastewater. When the wastewater is not re-used for additional hydraulic fracturing operations, it is either stored in underground disposal wells or pre-treated and then sent publicly owned treatment works (POTWs), where the fluids are eventually disposed of in bodies of water.242 In 2011, the EPA announced that it would promulgate new standards for the pre-treatment of flowback before it is sent to POTWs.243

232 Id. at 63-72. 233 Id. at 429, 513. Under subpart HH, Oil and Natural Gas Production Facilities, the “small glycol dehydration units” is defined as units with an actual annual average gas flowrate less than 85,000 scmd or actual annual average benzene emissions less than 0.90 Mg/yr; and under subpart HHH, Natural Gas Transmission and Storage Facilities, it is defined as units with an actual annual average gas flowrate less than 283,000 scmd pr actual annual average benzene emissions less than 0.90 Mg/yr. 234 Id. at 435, 518-19 (to be codified at 40 C.F.R. §§ 63.765(b)(1)(i), 63.1275(b)(1)(i)). 235 Id. at 73. 236 Id. at 440-41 (to be codified at 40 C.F.R. §63.769(c)). 237 Id. at 430-33, 513-16 (to be codified at 40 C.F.R. §§ 63.762, 63.1272). 238 Id. at 239. 239 Id. at 237. 240 Id. at 248. 241 See, e.g., 40 C.F.R. § 403.5 (regulating disposal of wastewater from oil and gas operations, including hydraulic fracturing). 242 EPA, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources 15. 243 76 Fed. Reg. 66,286 (Oct. 26, 2011).

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The potential parameters for these standards are largely unknown at this point, and the EPA’s announcement indicated that it would not propose such standards until 2014.244 The EPA’s comprehensive study indicates that it will be paying significant attention to wastewater storage and disposal.245 Further, unlike the SDWA, the CWA contains no exemption for hydraulic fracturing and the EPA therefore already possesses statutory authority to impose significant new requirements on the pre-treatment of flowback for disposal with POTWs.

[e] BLM Proposed Regulations

On May 4, 2012, BLM released proposed rules that would set requirements for well-bore integrity and establish flowback water standards for all hydraulic fracturing operations on federal public lands and tribal lands.246 The proposed rules would also require the public disclosure of chemicals used during hydraulic fracturing after fracturing operations have been completed.247 Significantly, instead of imposing substantive restrictions on hydraulic fracturing operations, the rule proposes to adopt procedural requirements.248

The proposed rules would require notifications to BLM before and after the well operations. Before the commencement of the operation, the proposed rules require operators to submit a Sundry Notice and Report on Wells249 to BLM and complete a Mechanical Integrity Test.250 After the completion of well stimulation operation, a Subsequent Report Sundry Notice is due within 30 days, which includes, among other things, the chemical disclosure.251 In addition, the proposed rule would require operators to store recovered fluids in tanks or lined pits.252

The proposed rules are under criticism from both industry and environmental groups. Industry and state officials are concerned that the rule would impose unnecessary burdens while offering little to no benefit.253 There is considerable debate over the extent to which the

244 Id. at 66,302; see also Larry Nettles and Hana Vizcarra, EPA Proposes to Adopt New Coalbed Methane and Shale Gas Wastewater Discharge Standards in 2013 and 2014, Vinson & Elkins Shale Insights – Tracking Fracking E-Communications, Oct. 27, 2011, http://www. velaw.com/. resources/EPAProposesAdoptNewCoalbedMethaneShaleGasWastewaterDischargeStandards.asp. 245 EPA, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources passim. 246 Oil and Gas; Well Stimulation, Including Hydraulic Fracturing, on Federal and Indian Land, 77 Fed. Reg. 27, 691 (proposed May 4, 2012) (to be codified at 43 C.F.R. pt. 3160). 247 Id. 248 Id. See also Bureau of Land Management Issues Proposed Rule Establishing Disclosure and Integrity Requirements for Hydraulic Fracturing on Federal and American Indian Lands, Latham & Watkins Client Alter No. 1341 (May 24, 2012). 249 77 Fed. Reg. at 27,695 (to be codified at 43 C.F.R § 3162.3-3(b)). A Notice of Intent of Sundry shall contain geological information; cement bond logs; perforation depth, water source, pump pressures and transportation routes; certificate of compliance; proposed well stimulation engineering design; and flowback fluid handling. The Notice is also required if the previous approval is more than five years old or new information about the relevant geology, the stimulation operation or technology, or the anticipated impacts on resources becomes available. 250 77 Fed. Reg. at 27,697 (to be codified at 43 C.F.R. § 3162.3-3(d)). 251 77 Fed. Reg. at 27,698 (to be codified at 43 C.F.R. § 3162.3-3(g)). The information required by the Subsequent Report Sundry Notice includes: the total fracturing fluid volume, the fracturing additives, the chemical makeup of all materials used in the fracturing fluid, the volume of recovered flowback water, the actual disposal method for those fluids, and reports of deviations from the approved original plan. 252 77 Fed. Reg. at 27,697-98 (to be codified at 43 C.F.R. § 3162.3-3(f)). 253 New Proposal on Fracking gives Ground to Industry, New York Times, May 4, 2012.

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proposed rule overlaps with existing state regulations.254 In addition, some tribal leaders have contended that the proposed rule would make natural gas development on tribal lands more cumbersome than on state or private property.255 By contrast, environmental groups and a number of members of Congress question why chemical disclosure should not happen before chemicals are used.256 The public comment period for the proposed rule closed September 10, 2012.257

[3] State and Local Regulations

The vast majority of the regulation concerning hydraulic fracturing occurs at the state and local level. This section summarizes key trends in state and local regulations that have occurred in the last year and are likely to remain at the forefront of shale development and hydraulic fracturing regulations in the near future. Like regulation at the federal level, a major issue for clean air regulations across the spectrum of oil and gas production facilities is aggregation. Accordingly, many state legislatures and agencies have been considering standards that would define whether and how to aggregate facilities for determining the applicability of certain permitting standards. Additionally, a variety of factors have contributed to more stringent standards for the withdrawal of water for use in hydraulic fracturing, both in Texas and in states in the Marcellus Shale play. An increasing number of states are also precluding the drilling and operation of wells in certain proximity to water sources or other important areas. Further, increased concerns about hydraulic fracturing have led many local governments to impose strict siting requirements for hydraulic fracturing or outright bans on the practice, though this has resulted in some lawsuits challenging the legality of such local regulation. Finally, a number of states have enacted new standards that require the public disclosure of components of hydraulic fracturing fluids.

[a] Aggregation

As with the potential aggregation of facilities under the CAA, state governments have increasingly treated distinct parts of natural gas recovery operations as a single facility for regulatory purposes. State regulatory authorities usually face the decision of whether or not to aggregate different sources of air emissions when attempting to construe definitions of “facility.” Typically, states use statutory language similar to that in the CAA and generally follow the federal test for defining contiguous or adjacent facilities. In Pennsylvania, for example, the statute defines a facility as an “air contamination source or combination of sources located on one or more contiguous or adjacent properties, and is owned and operated by the same person under common control.”258 In October of 2011, the Pennsylvania Department of Environmental Protection (“PADEP”) published an initial guidance document, which noted that the Department would determine whether or not to aggregate on a case-by-case basis and that the geographic

254 Bureau of Land Management Issues Proposed Rule Establishing Disclosure and Integrity Requirements for Hydraulic Fracturing on Federal and American Indian Lands. 255 See Bureau of Land Management’s Hydraulic Fracturing Rule’s Impact on Indian Trial Energy Development Before the Subcomm, Indian and Alaska Native Affairs, 158th Cong., (April 19, 2012). 256 See Bureau of Land Management Issues Proposed Rule Establishing Disclosure and Integrity Requiremetns for Hydraulic Fracturing on Federal and American Indian Lands. 257 77 Fed. Reg. 38,024 (June 26, 2012). 258 25 Pa. Code, Chapter 127, § 121.1.

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proximity of sources would be the most important factor in the determination, suggesting that a one-quarter mile distance would be the usual threshold for distinguishing between adjacent and non-adjacent sources.259 In October 2012, PADEP published revised guidance on aggregation which maintains the quarter mile rule and describes additional criteria to consider when making aggregation determinations for sources that are more than one-quarter mile apart.260

The New York Department of Environmental Conservation has also addressed the aggregation issue in its Supplemental Environmental Impact Statement (SGEIS), the most recent draft of which was released in September 2011.261 The Revised Draft SGEIS contains numerous requirements relating to air emissions and the permit process, which include a variety of mitigation measures, operational limitations for drilling and flowback, and standards for storage tanks. As to aggregation, the Revised Draft SGEIS proposes that New York follow the EPA standards in determining when the aggregation of facilities is appropriate.262

Texas is also trending toward the aggregation of facilities for permitting. In 2011, the Texas Commission on Environmental Quality (TCEQ) adopted new permit regulations for oil and gas facilities in the Barnett Shale region, which required that facilities located on contiguous or adjacent properties, under common control, with the same standard industrial classification code, that were operationally dependent on each other, and located within one quarter-mile of a project emission point, vent, or fugitive component, be covered by the same permit.263 Expansion of this regulation beyond the Barnett Shale is unlikely in the near future, however, as the Texas legislature enacted legislation in June of 2011 that requires the Commission to complete a regulatory analysis prior to adopting new or amending existing permit standards and only after determining that the emissions limits are necessary.264

Thus, in the majority of states, there has been significant activity in the aggregation area between lawsuits and regulatory developments, but states have continued to look to the federal standards in determining the appropriate scope of aggregation. Activity at the federal level, including EPA rulemaking and citizen-suits challenging non-aggregation decisions, is likely to be heavily influential for state air quality standards, in addition to federal regulations under the CAA.

259 Pa. Dep’t of Envtl. Prot. Bureau of Air Quality, “Guidance for Performing Single Stationary Source Determinations for Oil and Gas Industries,” No. 270-0810-006, Oct. 12, 2011, available at http://files.dep.state.pa.us/Air/AirAggregation/AirAggregationPortalFiles/TechnicalGuidance_SingleSourceAirAggregation_101211.pdf. 260 Pa. Dep’t of Envtl. Prot. Bureau of Air Quality, “Guidance for Performing Single Stationary Source Determinations for Oil and Gas,” No. 270-0810-006, Oct. 6, 2012. 261 Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas, and Solution Mining Regulatory Program (Revised Draft SGEIS), Sept. 7, 2011, available at http://www.dec.ny.gov/data/ dmn/rdsgeisfull0911.pdf. 262 Id. at 6-110. 263 Air Quality Standard Permit for Oil and Gas Handling and Production Facilities, available at http://www.tceq.texas.gov/assets/public/permitting/air/Announcements/oilgas-sp.pdf (to be codified at 30 Tex. Admin. Code 116.620). 264 Act of May 29, 2011, 82d leg., R.S., 2011 Tex. Sess. Law Serv. Ch. 1080, 1 (S.B. 1134) (to be codified at Tex. Health & Safety Code 382.051961).

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[b] Water Withdrawal

Concerns stemming from both hydraulic fracturing and water scarcity have resulted in tighter rules on the withdrawal of water for hydraulic fracturing. In Texas, severe droughts prompted lawmakers in 2011 to enact legislation authorizing state officials to temporarily suspend water rights and adjust the diversions of water in the event of a drought or other water shortage emergency. The regulations implementing the legislation authorize the executive director of the Texas Commission on Environmental to suspend or adjust senior water rights, in the event that the public welfare so requires, with a post-order hearing available to challenge that action.265 Pennsylvania, also responding to water shortages, temporarily suspended water withdrawals in a number of areas, and this had a significant effect on hydraulic fracturing operations at wells in the area.266 Both the Texas and Pennsylvania cases serve as a reminder that water shortages can result in significant disruptions to established water rights, which will often impact hydraulic fracturing operations.

Some states have imposed more permanent requirements for water withdrawal that are specifically directed at hydraulic fracturing operations. In Michigan, for example, operators of “high volume hydraulic fracturing” operations must now report the total volume of water withdrawn, depth of the well, frequency of withdrawal, and other information.267 Furthermore, they must evaluate the possible consequences of water withdrawal and drill a monitoring well to ensure that the withdrawal does not adversely affect freshwater wells, if any are in the vicinity.268 Likewise, Pennsylvania requires that any user who withdraws more than 10,000 per day over a 30-day period register with DEP.269 And in West Virginia, withdrawals of more than 750,000 gallons of water per month from state waters require registration with WVDEP’s Division of Water and Waste Management.270 Additionally, applicants for well work permits for the drilling, fracturing, or stimulation of horizontal wells who expect to withdraw more than 210,000 gallons from waters of the state over a 30-day period are required to file a water management plan in order to receive the permit.271 New York has also imposed new water withdrawal permitting requirements applicable to any person withdrawing more than 100,000 gallons a day in New York; the law became effective February 15, 2012, although applications for non-public water supplies are not required until enactment of implementing regulations.272 The new permit will require a state agency to adopt regulations addressing operation standards, monitoring, reporting, and recordkeeping requirements, and protective measures for potable water sources.273

Additional regulations regarding water withdrawal may emerge from the Delaware River Basin Commission (DRBC), an agency created by interstate compact, with control

265 See 30 Tex. Admin. Code § 36.1 et seq. (2012); Tex. Comm’n on Envtl. Quality, Development of a Rule for Drought or Water Shortage Conditions, http://www.tceq.texas.gov/legal/events/drisawr.html. 266 Press Release, Susquehanna River Basin, 36 Water Withdrawals for Natural Gas Drilling and Other Purposes on Hold to Protect Streams (July 19, 2011), available at http://www.srbc.net/ newsroom/News. 267 Michigan Department of Environmental Quality, Supervisor of Wells Instruction 1-2011 (2011), at 1, available at http://www.michigan.gov/documents/deq/SI_1-2011_,353936_7.pdf. 268 Id. at 2-3. 269 25 Pa. Code, Chapter 110. 270 Water Resources Protection Act, W. Va. Code § 22-26-3, et seq. 271 Horizontal Well Act, W. VA. CODE § 22-6A-7(e). 272 Environmental Conservation Law § 15-1501. 273 Id.

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responsibilities spanning parts of Pennsylvania, Delaware, New Jersey, and New York. The DRBC published draft regulations for natural gas development in November of 2011, which would govern all natural gas wells in the Delaware River Basin.274 If the proposed rules are adopted, Bulk Water management permits will be required for each well pad and these must be obtained prior to the initiation of any construction at the site.275 In addition to water withdrawal, the DRBC draft regulations would affect wastewater disposal, require that operators complete a Natural Gas Development Plan in compliance with siting and ecological restoration requirements, and impose financial assurance requirements.276

The experiences in these states recommend growing concern with the significant use of water for oil and gas production, especially when there is a significant shortage of water. In the event that Texas continues to experience dry summers, these issues will remain critically important. States in the Marcellus Shale may also follow the DRBC and continue the move toward more significant restrictions on water withdrawal.

[c] Siting regulations for proximity to critical areas

An increasing number of states have prohibited both hydraulic fracturing and oil and gas production operations generally in the proximity of water sources, urban areas, and areas that are potentially hazardous. The most common types of regulations either prohibit the construction of oil and gas wells in close proximity to wells used for potable water,277 or impose significant restrictions and regulations on such wells.278 West Virginia279 and Pennsylvania280 have recently established minimum distances between wells used for oil and gas extraction and those used for potable water or more heavily regulate extraction in close proximity to such water. For example, Pennsylvania’s Act 13281 extends the setback distance for unconventional wells from 200 feet to 500 feet from existing buildings or water wells, unless consented to by the owner of the building or water well.282 Act 13 establishes a 100 ft. setback requirement for unconventional wells from the edge of the disturbed area associated with the well site to the edge of any solid blue lined

274 Delaware River Basin Commission, Natural Gas Development Regulations, Nov. 8, 2011, available at http://www.state.nj.us/drbc/notice_naturalgas-draftregs.htm. 275 Id. at § 7.3(b)(2). 276 Id., passim. 277 E.g., PA Act 13 § 3215(a) (extending the setback distance for unconventional wells from 200 feet to 500 feet from existing buildings or water wells, unless consented to by the owner of the building or water well); N.Y. Comp. Codes R. & Regs tit. 6 § 553.2. 278 E.g., Colorado Oil and Gas Conserv. Comm’n, Rule 317B. 279 H.B. 401 (W. Va. 2011). 280 H.B. 1950 (Pa. 2012). 281 Earlier this year, the Pennsylvania General Assembly enacted Act 13, which substantially revised the State’s previous oil and gas laws. Governor Corbett signed Act 13 into law on February 14, 2012, and most of its provisions took effect on April 16, 2012. Act 13 applies to all unconventional oil and gas wells in Pennsylvania, which the legislation defines as wells drilled to produce natural gas from shale existing below the base of the Elk Sandstone or its geological equivalent where natural gas generally cannot be produced at economic flow rates or in economic volumes except by hydraulic fracturing or by the use of multilateral well bores. Certain provisions of Act 13 restricting local governments’ ability to zone and regulate drilling were recently held unconstitutional by a Pennsylvania trial court. Robinson Township, et al. v. Pennsylvania, 284 M.D. 2012 (Pa. Commonwealth Court, July 26, 2012). An appeal is pending. 282 PA Act 13 § 3215(a).

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stream, spring or body of water.283 Likewise, West Virginia prohibits drilling of wells within 250 feet of existing water wells or springs used for human or domestic animal consumption.284 Wells also may not be drilled within 150 feet from any perennial stream, natural or artificial lake, pond or reservoir, or wetland, or within 300 feet of a naturally reproducing trout stream.285 Nor may they be within 1,000 feet of a surface or groundwater intake of a public water supply.286

Colorado is the most recent state to enact new setback requirements, approving new rules on January 9, 2013.287 The rule expands setback requirements to 500 feet statewide and 1000 feet from buildings with large numbers of people (such as schools, nursing homes, and hospitals) unless approved by the Colorado Oil and Gas Conservation Commission (“COGCC”). The new rule also expands notice and outreach requirements and imposes additional requirements for wells drilled within 1000 feet of an occupied structure, including closed loop drilling, liner standards, gas capture, and nuisance controls. The COGCC also recently approved new rules requiring operators to sample water wells near drilling sites before and after drilling activities.288 As of January 19, 2013, the text of these new rules was not yet available on COGCC’s website.

The Arkansas legislature, likely unsettled by claims that certain hydraulic fracturing operations have resulted in unusual seismic activity,289 has considered prohibiting the construction of wells in close proximity to fault lines in the proposed legislation.290 Finally, several states in the Marcellus Shale heavily regulate the development of wells above coal seams,291 with Pennsylvania prohibiting the development of multiple natural gas well clusters within 2,000 feet of each other in such areas by a statute enacted in 2011.292

New York’s Revised Draft SGEIS includes significant siting restrictions, based primarily on proximity to water sources. Existing law already prohibits oil and gas wells from being located within 50 feet of any public stream, river, or other body of water.293 The Revised Draft SGEIS would extend this prohibition to the entire New York City and Syracuse watersheds (including a 4,000-foot buffer zone around such watersheds), within 500 feet of primary aquifers, within 2,000 feet of public water supply wells, river or stream intakes or reservoirs, within 500 feet of private potable water wells or springs, and within any 100-year floodplain.294 Many

283 Id. at § 3215(b)(2). 284 W. VA. CODE § 22-6A-12(a). 285 W. VA. CODE § 22-6A-12(b). 286 Id. 287 Colorado Oil and Gas Conservation Commission, Press Release, “COGCC Approves Sweeping New Measures to Limit Drilling Impacts,” Jan. 9, 2013, available at http://cogcc.state.co.us/RR_HF2012/Setbacks/COGCC_APPROVES_SWEEPING_NEW_SETBACK_RULES.pdf. 288 Colorado Oil and Gas Conservation Commission, Press Release, “COGCC Approves Pioneering New Groundwater Protections,” Jan. 7, 2013, available at http://cogcc.state.co.us/RR_HF2012/Groundwater/COGCC_APPROVES_PIONEERING_NEW_GROUNDWATER_PROTECTIONS.pdf. 289 Frank A. Verrastro, Lisa Hyland, and Molly Walton, “Fracking and Seismic Activity,” Center for Strategic and International Studies, http://csis.org/publication/fracking-and-seismic-activity. 290 H.B. 1396, 2011 Leg., 88 Sess. (Ar. 2011). 291 West Virginia provides very specific procedures that operators must follow in such areas, including a public hearing to air objections to the operations. W. Va. Code 22-6-12. 292 S.B. 265 (Pa. 2011). 293 N.Y. Comp. Codes R. & Regs. Tit. 6 § 553.2. 294 Revised Draft SGEIS, at 3-14 to 3-15.

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siting restrictions have been enacted at the local level, an issue addressed in the following section.

Many of the siting requirements will likely be heavily influenced by the EPA’s study on hydraulic fracturing. If the study indicates significant concerns arising from hydraulic fracturing, then more restrictive siting regulations will likely be one of the early steps taken by state and local governments to mitigate the risks associated with the activity. These will likely focus on the proximity of oil and gas operations to water sources, although additional siting restrictions may result, depending on the outcome of the study.

[d] Prohibitions and regulation at the local level

Local governments have been increasingly active in passing hydraulic fracturing regulations, though this occasionally has resulted in pushback at the state level. The power of local governments to regulate or prohibit hydraulic fracturing within their jurisdiction varies depending on the applicable state regulatory regime. In Louisiana, for example, local government attempts to regulate hydraulic fracturing are expressly preempted by state law.295 In Pennsylvania, where localities had significantly more regulatory power, newly enacted Act 13 limits the ability of local communities to regulate oil and gas activities within their borders; however, these restrictions have been overturned in state appellate court and the legal battle over municipalities’ regulation of drilling continues.

Several states, including Texas, have a balanced approach in which local governments may impose time, place, and manner restrictions within city limits. Fort Worth, for example, requires that all oil and gas production activities within the city limits secure a permit and demonstrate proof of financial responsibility and insurance, in addition to setback requirements, noise restrictions, and other limitations.296 Additionally, the drought in Texas, which reached its height in the summer of 2011, resulted in significant activity by local groundwater conservation districts and municipalities to limit the use of water for hydraulic fracturing. Though Texas state law prohibits these districts from specially requiring permits for oil and gas drilling or exploration, some localities have argued that water for hydraulic fracturing does not fall within this provision and may attempt to require permits for the use of such water.297

New York has been a hotbed of activity with regard to hydraulic fracturing regulation. Currently, there are approximately one hundred municipalities within the State of New York that have banned hydraulic fracturing to some extent. Notably, the New York state legislature is considering legislation that would render the preemption argument moot. The New York State Assembly passed a bill that would give municipalities greater powers to regulate oil and gas production within their jurisdiction. The State Senate did not approve it initially but it was

295 Energy Mgmt. Corp. v. City of Shreveport, 397 F.3d 297, 303-04 (5th Cir. 2005). 296 Fort Worth, TX, Ordinance 18449-02-2009, 15-12(A)(16), 15-34, 15-41, 15-42(C), 15-43 (Feb. 3, 2009). 297 Mike Lee, Parched Texans Impose Water-Use Limits for Fracking Gas Wells, Business Week, Oct. 6, 2011, http://www.businessweek.com/news/2011-10-06/parched-texans-impose-water-use-limits-for-fracking-gas-wells.html. The Texas Railroad Commission has stated, however, that it interprets the law to include hydraulic fracturing within the exemption for oil and gas exploration operations. Railroad Commission of Texas, Barnett Shale: Water Use in Association with Oil and Gas Activities Regulated by the Railroad Commission of Texas, http://www.rrc.state.tx.us/ barnettshale/wateruse.php.

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reintroduced in the Senate in 2012.298 Some commentators have suggested that, if a state law giving local governments greater regulatory powers over oil and gas operations is passed, companies affected by these restrictions may still claim that local government prohibitions amount to regulatory takings, triggering their right to just compensation under the Fifth Amendment.299 Given the current state of things, further developments on hydraulic fracturing in New York are likely to unfold in the coming year.

[e] Disclosure standards

Perhaps the most significant development in 2011 and the first part of 2012, in terms of the number of states involved, has been the promulgation of requirements that companies disclose the chemicals used in hydraulic fracturing fluids. Several states passed laws or regulations establishing or overhauling chemical disclosure regimes, and several additional states are expected to follow suit.300 Virtually all of the state disclosure regimes require companies to disclose the maximum pressure used during the process, type and volume of fluid and proppants used, the trade names of all additives used, the concentration or volume of each additive in the fluid, and the chemical abstract service (CAS) numbers of all chemical constituents of the additives. Some states also require the material safety data sheets (MSDS) for the additives, either instead of or in addition to CAS numbers. Additionally, some states require the disclosure of information such as pressures recorded during flowback operations and the sources of water used.301

The greatest diversity in the disclosure requirements lies in the manner in which companies are to disclose the required information. Some states specifically require that the companies publish the information on a public website, such as FracFocus.com,302 while others require that the companies send the requested information to a state agency, which may either publish the information on its own website or make it available on demand.303 In his 2011 State of the Union speech, President Obama confirmed that the Department of the Interior would adopt similar disclosure requirements for hydraulic fracturing operations on federal lands.304 And, as discussed in section 2(e), supra, on May 4, 2012, BLM in fact released proposed rules requiring

298 New York Senate, S3472-2011 (2012) http://open.nysenate.gov/legislation/bill/S3472-2011. 299 Hodgson Russ LLP, Can Municipalities Enact Local Laws Regulating the Oil and Gas Industry?, Jan. 13, 2012, http://hodgsonruss.com/Home/News_Seminars/Articles_and_Alerts/CanMunicipalitiesEnactLocalLawsRegulatingtheOilandGasIndustry. 300 E.g., Ark. Oil and Gas Comm’n, Gen. R. and Reg. B-19(k)(1)-(2), 19(l)(3)(A) (2011); Col. Oil and Gas Conserv. Comm’n, Rule 205A; La. Admin. Code tit. 43, pt XIX § 118; Tex. Admin. Code § 3.29(B). 301 E.g., 25 Pa. Code § 78.122. Pennsylvania recently enacted legislation that elaborates on the state’s hydraulic fracturing fluid disclosure requirements. See 58 Pa. Cons. Stat. § 3222.1 (2012). 302 E.g., Tex. Admin. Code § 3.29(B). 303 E.g., Ohio Rev. Code Ann. § 1509.10. 304 President Barack Obama, Remarks by the President in State of the Union Address (Jan. 24, 2011), available at http://www.washingtonpost.com/politics/state-of-the-union-2012-obama-speech-excerpts/2012/01/24/gIQA9D3QOQ_story.html?hpid=z1 (“I’m requiring all companies that drill for gas on public lands to disclose the chemicals they use.”); see also Ayesha Rascoe, U.S. to Require Details of Fracking on Federal Land, Reuters, Oct. 31, 2011, http://www.reuters.com/article/2011/10/31/us-usa-shalegas-regulation-idUSTRE79U4A920111031.

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the public disclosure of chemicals used during hydraulic fracturing after fracturing operations have been completed.305

The most important variation in disclosure regimes is the amount of protection afforded to trade secrets. Most states offer significant protections for trade secrets, though many do not allow these protections to prevent disclosure to the state agency for reasons other than publication to the general public,306 or to health professionals or emergency responders,307 and more basic information about chemicals used must typically be furnished despite trade secrets.308 Three of the most recent states to pass hydraulic fracturing fluid disclosure requirements are Ohio,309 Oklahoma310 and Pennsylvania.311 All include some form of trade secret protection. Interestingly, Ohio and Pennsylvania originally only required operators to make MSDS available to the public, but later chose to pass disclosure requirements similar to Texas and other western states.

In Wyoming, a state with a relatively long history of chemical disclosure requirements for hydraulic fracturing, the Wyoming Oil and Gas Conservation Commission (WOGCC) had approved 146 requests for exemption from disclosure on the basis of its trade secret protections, while rejecting only two requests by August 24, 2011.312 This broad protection has led to unrest within the state among environmental groups, and in March 23, 2012, the Powder River Basin Resource Council and several other parties filed suit against the WOGCC seeking broader disclosures from the agency regarding hydraulic fracturing fluid contents.313 The lawsuit claims that the WOGCC unlawfully withheld the identity of hydraulic fracturing chemicals and inappropriately classified some information as trade secrets or confidential business information.314

There are a few states with shale plays that do not provide for the protection of trade secrets. West Virginia does not make public any information disclosed to the Department of Environmental Protection.315 Michigan also does not provide trade secret protections for information that the state may request regarding the products and chemicals used in oil and gas operations.316 North Dakota recently adopted a unique disclosure requirement.317 Unlike other

305 Oil and Gas; Well Stimulation, Including Hydraulic Fracturing, on Federal and Indian Land, 77 Fed. Reg. 27, 691 (proposed May 4, 2012) (to be codified at 43 C.F.R. pt. 3160). 306 E.g., Ark Oil & Gas Comm’n Gen. R. & Reg. B-19(k)(8) (2011); id. R. B-19(l)(3)(C). 307 E.g., Tex. Admin. Code § 3.29(D)(4)). 308 E.g., Col. Oil and Gas Conserv. Comm’n, Rule 205A. 309 Ohio Rev. Code Ann. § 1509.10. 310 Okla. Admin. Code § 165:10-3-10. 311 58 Pa. Cons. Stat. § 3222.1. 312 Thomas E. Kurth, Cameron Gulley & William D. White, Shaking Up Established Case Law and Regulation: The Impacts of Hydraulic Fracturing, The Advocate (Winter 2011) 25 (statistics as of August 24, 2011). 313 Powder River Basin Resource Council, et al. v. Wyoming Oil and Gas Conservation Commission, No. XXXX (7th Wyo. Dist. Ct. filed March 23, 2012). 314 Complaint for Declaratory Relief at 4, Powder River Basin Resource Council, et al. v. Wyoming Oil and Gas Conservation Commission, No. XXXX (Mar. 23, 2012). 315 § 1509.10; W. VA. CODE R. §§ 22-6-22, 35-8-3.3e. 316 R 324.416(3). 317 North Dakota’s new rules took effect April 1, 2012. North Dakota Industrial Commission, Oil and Gas Division, Press Release, March 14, 2012, available at https://www.dmr.nd.gov/oilgas/pressreleases/PressRelease03142012.pdf.

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states, the North Dakota rules do not provide any trade secret protections. However, the disclosure requirements in North Dakota would only be triggered when a company does not use a frac string in its operations and it only requires submission of those elements made viewable on the Frac Focus website.318 This framework thereby offers a significant incentive to utilize a particular technology during hydraulic fracturing. This approach could be replicated in other states or at the federal level to require the adoption of certain technologies in exchange for trade secret protection or exemption from other regulatory requirements.

In sum, there has been an increase in disclosure requirements over the past year, but a consensus has emerged providing for trade secret protections, except in very limited circumstances. Other states, and the federal government under TSCA, will likely afford similar protection to trade secrets and proceed with disclosure requirements in a generally similar manner. However, overly broad application of trade secret protections could lead to a backlash from local environmental groups and result in challenges to trade secret claims.

318 The new rule only requires chemical disclosure for hydraulic fracture stimulation performed through an intermediate casing string. See § 43-02-03-27.1(2).

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§ 4.01 Conclusion

There has been an extensive amount of litigation and regulatory activity that impacts shale development in the United States. As detailed above, the majority of that activity is focused on the combined use of horizontal drilling and hydraulic fracturing as a means of accessing our country’s abundant shale gas reserves. Given the polarized views held by hydraulic fracturing proponents and detractors, further litigation and regulation can be expected in the future.

On the litigation front, lawsuits like those detailed herein will likely continue to have a strong presence in the courts until horizontal drilling and hydraulic fracturing are proven by trusted sources to be environmentally safe. In the meantime, different jurisdictions will likely take a variety of approaches in applying their respective precedents on procedure, torts, property rights, and preemption as they address the many and varied issues that arise in the context of shale-related litigation. Inevitably, the variability and occasional unpredictability of these approaches will present a number of opportunities and challenges for operators and plaintiffs alike.

As to regulation, there is likely to be increasing diversity in certain aspects of state regulatory regimes, particularly with regard to siting and permitting requirements and water withdrawal and disposal regulations. At the same time, there is increasing similarity in state chemical disclosure regimes and the EPA’s interest in hydraulic fracturing may yield new federal regulatory requirements pertinent to hydraulic fracturing, including standards for air emissions and water pre-treatment. Additionally, the EPA’s publishing of its first round of findings in its study of hydraulic fracturing this year may prompt additional regulatory activity at the state and federal level, as well as provide impetus for both citizen/environmental and industry challenge lawsuits.

US 1754605v.1

The Future of Hydraulic Fracturing Litigation

Environmental Implications of Shale-Gas Development and Hydraulic Fracturing:

Stephanie Meadows American Petroleum Institute Washington, DC James Saiers Yale School of Forestry & Environmental Studies New Haven, CT James Thompson Vinson & Elkins LLP Houston, TX

Environmental Implications of Shale‐Gas Development and Hydraulic Fracturing

Jim Saiers, Professor of HydrologyYale School of Forestry & Environmental Studies

Opinions Vary on Shale‐Gas Development

Pollute our air and streamsDeplete drinking‐water aquifers

Devastate the landscapeCrowd‐out renewables

Shale‐gas development is a curse that will

Affordable energyClimate‐change mitigation

National energy securityReducing state debt

Shale‐gas development is a blessing that is key to

Overview of Presentation

Shale‐gas production and history of development

Stages of shale‐gas extraction, including fracking

Environmental impacts

Water quality

Air quality and GHG emissions

Landscape alteration

0

1

2

3

4

5

6

1985 1990 1995 2000 2005 2010 2015

Annu

al Produ

ction (Tcf)

U.S. Shale‐Gas Boom

Production increased 12‐fold over last decade

Shale‐Gas Timeline

1st commercial gas well in Fredonia, NY

Gas productionin Barnett booms

Marcellus gas is discovered

Mitchell Energy combines horizontal drilling with HVF

Hydraulic fracturing first used

Development of  directional drilling

Marcellus drilling begins

Stages of Shale‐Gas Extraction

Mineral Leasing

Permitting

Site Preparation

Gas‐Well Drilling and Casing

Hydraulic Fracturing

Gas‐Well Production

Mineral (Gas) Leasing

Primary lease

Often (but not always) five years

One‐time bonus/rental payment: $5 to > $4,000 per acre

Secondary lease

Lasts as long as operations continue

Royalty payments: percentage of price of gas produced

Permitting

Permit applications require specification of plans for

Gas well siting and drilling

Water management

Construction and excavation

Well closure

Regulations governing permitting are generally set by the state

Preparation of Site forShale‐Gas Drilling

Site preparation involves engineering the landscape to accommodate 

the drilling pad

reservoirs for the storage of water used in operations

pipelines and compressor stations to transfer natural gas 

roads to access the site

May involve forest‐clear cutting, excavation, and reshaping of area’s topographical contours 

Gas‐Well Drilling and Casing

Shale‐gas well penetrates downward before turning laterally to parallel the gas‐bearing shale layer

Well “cased” with concentric rings of steel pipe

Steel casings are surrounded by cement

Cemented casing maintains well‐bore integrity,permits conveyance of gas, and isolates gas well from near‐surface aquifers

Hydraulic Fracturing

Hydraulic fracturing commences once the drilling is finished and the well bore is encased in steel casing and fixed in place by cement. 

A perforation gun is lowered to shoot holes in the lateral part of the casing.

Then large volumes of a water‐based fluid, containing various dissolved chemicals and sand, is pumped down the borehole and out through the perforations in the casing. 

The rapid introduction of frac fluid increases the fluid pressure within the shale formation, and fractures are generated as pressures exceed the shale’s tensile strength.   

The sand, called the proppant, wedges in the fractures and keeps them open after injection stops and the pressure is relieved. 

To increase the fracture density, frac‐fluid introduction is performed repeatedly on isolated sections of the lateral, which are called stages

The fractures extend tens of meters radially outward from the well bore. 

Gas‐Well Production

Gas‐Well Production Decline Curve

During production, gas is collected from the well and transmitted by pipeline to market. 

Initial production is great, but decreases quickly.   Within one year, production may decline to 75% of the initial rate. 

There’s considerable well‐to‐well variation in these curves.  

Some wells produce at furious rates at the outset and could produce for 20 years before their economic limit is reached.  

Other wells have moderate rates of initial production that may dwindle to non‐economic levels comparatively quickly, making them candidates for abandonment or re‐stimulation

Shale‐Gas Development and Land Disturbance

Studies in Pennsylvania’s Marcellus‐Shale Region:

A well pad and its infrastructure disturb 9 acres1

1,465 well pads in PA (as of July 2011)2

Total land disturbance in PA: 20 square miles

Most development on forest and agricultural lands

Small overall footprint, but habitat disruption, forest fragmentation, and erosion are concerns

1Johnson, 20102Drohan et al., 2012

Methane Contamination and Shale‐Gas Extraction

Improperly cased/cemented wells allow methane (CH4) to migrate along borehole and escape into aquifers 

Standard methods for well construction are intended to minimize probability of methane release 

States have tightened casing/cementing rules Baseline (pre‐drill) monitoring protects both parties

Leaky casings implicated in CH4 contamination of  Dimock, PA water wells

CH4

Marcellus

drinking

‐water

aquifer

gas‐charged units

Natural Occurrence of Methane: It’s Not Just the Drillers

Methane was present in drinking‐water aquifers prior to shale‐gas development:

Methane contamination of drinking‐water aquifers can also occur from

• Abandoned gas wells from old drilling operations

• Underground coal mining

• Native shallow (non‐Marcellus) gas

• 49 of 91 water wells sampled within Tioga County in 2004‐20051

• 24% of 189 water wells sampled in northeast and southwest PA2

1Breen et al., 20052Boyer et al., 2011

“I'm not aware of any proven case where the fracking process itself has affected water.”

‐‐ Lisa Jackson, Former Administrator of U.S. EPA

“Hydraulic fracturing has a nasty track record of creating a toxic chemical soup that pollutes groundwater and streams.”

‐‐ Rebecca Wodder, former nominee, Assistant Secretary for Interior Department 

Groundwater Contamination by Frack Chemicals: Two Views 

aquifer

≈1

mile

Marcellus

PotentialMechanisms of Freshwater Contamination by Hydraulic Fracturing

Surface spills of frac water & flow‐backDuring tanker‐truck transportAccidental releases at drill sitesLeaking pits

Chemical migration from frac zone

frac

ture

s

old

gas

wel

l

migratio

n pa

th Old gas wells & natural fractures as potential conduits

No systematic study of this phenomenon

Shale‐Gas Extraction Can Affect Air Quality

American Lung Association Letter to Obama (April 2012):

“We see irrefutable evidence of serious damage to human health from air pollutants emitted during natural gas production, including sulfur dioxide, nitrogen oxide, and volatile organic compounds (VOCs), benzene and formaldehyde, as well as increasing levels of ozone and particulate matter.”

Shale Gas and Greenhouse Gas Emissions

CO2 emitted during flaring of gas wells

CH4 emitted by venting of gas wells and by leakage during transmission

Estimates of CH4 emissions range from < 2% to 8% of CH4production

Emissions at upper end of this range imply a larger lifecycle greenhouse gas  footprint for shale gas than coal

flaring a gas well

Atmospheric Emissions: What’s Being Done

New EPA rules require “green completions” that are projected toReduce emissions of VOCs and CH4

Save industry $11 to $19 million

Retrofit diesel‐powered drill rigs, pumps, and compressors with  cleaner‐burning CH4‐powered engines

Leak detection and prevention

Additional Considerations(for Panel Discussion) 

Other environmental impacts (e.g., earthquakes, freshwater utilization in arid regions) 

Proper roles for local, state, and federal regulatory agencies

Socioeconomic impacts

Public health

Success of science in evaluating risks