United States: Shale Gas Issues: Squeezed Between Necessity and Reality

Originally published February 10, 2012

Keywords: shale gas, onshore shale basins, natural gas, shale formations

"Total annual production volumes of 3 to 4 trillion cubic feet may be sustainable for decades. This potential for production in the known onshore shale basins, coupled with other unconventional gas plays, is predicted to contribute significantly to the US's domestic energy outlook."
~ Modern Shale Gas Development in the United States—A Primer, US Department of Energy (April 2009).

"Estimates of these [fracturing] distances...are at best imprecise. Clues about the direction in which fractures are likely to run from the well may be derived from seismic and other data, but virtually nothing can be done to control that direction; the fractures will follow Mother Nature's fault lines in the formation.... One difficulty is that the material facts are hidden below miles of rock, making it difficult to ascertain what might have happened."
~ Coastal Oil and Gas Corp. v. Garza Energy Trust, et al., 268 SW 3d 1 (Tex. 2008).

"For whoever owns the soil, it is theirs all the way to Heaven and down to Hell."
~ United States v. Causby, 328 US 256, 260-261 (1946), citing Lord Coke's approval of the ancient maxim.¹

SECTION 1. INTRODUCTION

The relatively recent technological development of combining hydraulic fracturing and horizontal drilling to produce large quantities of natural gas (and liquids in many cases) from shale formations in the United States has and will likely continue to have significant impact on energy production. These developments will influence not only the price of hydrocarbons but also the economics of alternative energy development. At the same time, the prospect of conducting drilling activities, particularly in densely populated areas and those not familiar (at least recently) with oil and gas operations, has focused attention on potential risks associated with these activities. Not surprisingly, then, there has been a great deal of positive and negative excitement due to the current growth in hydrocarbon exploration and production in shale formations. This paper addresses three legal risk areas: (1) environmental regulatory and litigation risks, (2) nearby property owner damage and contamination litigation risks, and (3) securities law risks— with an acknowledgement to the concomitant political risks. While these risks cannot be eliminated, the purpose of the paper is to provide recommendations to those involved in the development and production of shale gas reserves that will mitigate these risks. We focus here on natural gas, but many of the issues will be similar for shale oil.

In Section 2 and 3, this paper discusses the basics of shale gas reserves and the process required for their development. While most of the controversy has centered on hydraulic fracturing, the use of horizontal drilling also plays a role in the current and expected controversies. The current growth in shale gas operations has been accompanied by highly publicized environmental concerns, primarily based on the possibility of groundwater contamination and the large amounts of water required for fracturing operations. These concerns have begun to produce a tentative regulatory response in the form of proposed legislation and regulations by the various state and federal governments. In addition, lawsuits have been filed by public interest groups as well as local landowners. These cases are typically based on the common law causes of action for trespass, negligence and nuisance, with or without a request for injunctive relief, and strict liability for violation of statutory and regulatory prohibitions. Due to their relatively recent vintage, these cases have not yet resulted in reported appellate decisions. The environmental and regulatory aspects of hydraulic fracturing of shale gas formations are discussed in Section 4.

Migration of frac fluids across property lines, resulting in claims of contamination of neighboring properties, can also lead to actions in trespass. Less well known, but immediately apparent upon review of local newspapers and blog sites, is the perceived "lesser twin" of fracing, namely the common concern of nearby landowners and leaseholders about the possibility of the subsurface drainage of oil and natural gas from their property to an adjacent property as a result of powerful hydraulic fracturing of deep shale deposits. This concern, even in regions as distant from Texas as Pennsylvania, often includes dire reference to a 2008 Texas Supreme Court case, referred to around the country as the Garza case. The common law "rule of capture" plays a pivotal role in resolving drainage disputes, and its application (or lack thereof) provides a legal rationale for the differing treatment of drainage and contamination. Section 5 will analyze the common law principles that will play an important part in shaping the claims of nearby landowners with respect to the primary areas of concern, contamination and drainage.

Finally, for publicly traded companies the very recent commencement of shale gas exploration and production, and resulting limitations in the production data available from which to estimate reserves in place and those economically recoverable, create new challenges for securities law disclosures. These requirements raise issues that may prove problematic until shale gas production and its associated technology mature and become better understood. Securities issues associated with shale gas reserves and their development are discussed in Section 6.

SECTION 2. SHALE RESERVOIRS

The United States has very extensive reserves of oil and natural gas locked in large shale formations across the country. These shale formations often overlap conventional natural oil and gas basins, but are typically more than a mile deep. Because of the very low permeability of shale, these formations have only relatively recently been explored, and only a few have begun to be developed, most notably the Barnett Shale in North Texas, the Bakken Shale in the Dakotas and Montana, the Marcellus Shale in the Appalachians, the Eagle Ford Shale in South Texas, the Haynesville Shale in Louisiana and the Woodford Shale in Oklahoma. Development is currently more active in the fields that are rich in liquids because of the current low price of gas in the United States and the high price of oil. Commercial production from these shale fields requires directional drilling, in which a drill goes vertically into the earth for several thousand feet to the desired depth and is then turned so as to drill horizontally to access a larger portion of the reservoir. Since the shale formations are made up of hard, impermeable rock with micro-pores filled with natural gas and some liquids, it is then necessary to crack, or fracture, this rock to allow the gas and liquids to flow back up the wells.² This technique is called hydraulic fracturing, or "fracing" as commonly known in the energy industry.

SECTION 3. HYDRAULIC FRACTURING IN SHALE GAS FORMATIONS

While hydraulic fracturing is not itself a new technique, the combination of fracturing and horizontal drilling to produce natural gas from tight shale formations only began in earnest in 2002-2003.³ The primary difference between modern shale gas development and conventional natural gas development is the extensive use of this combination of horizontal drilling and high-volume hydraulic fracturing.⁴ The combination of these two technologies that have been available for decades, coupled with technological advances in equipment and cost reductions, is the key to unlocking the vast reserves of shale gas. A well is typically more than a mile deep and its horizontal, or lateral, length may extend from 1,000 to 5,000 feet. The hydraulic pressure creates fissures, or cracks, in the rock that propagate along natural fault lines in an elongated elliptical pattern up to 3,000 feet from the well bore in opposite directions.

The hydraulic fracturing of shale is typically performed in four or more "stages," with each stage using different volumes and compositions of water-based fluids. The fracturing fluid is primarily water (90%), chemical additives (1-2%) and proppants (8-9%). The chemical additives have included hydrochloric acid (to initiate cracks by dissolution), glutaraldehyde (to act as a biocide), ammonium persulfate (to delay polymer breakdown), dimethyl formamide (to inhibit corrosion), borate salts (to maintain fluid viscosity), polyacrylamide (to reduce friction), hydroxyethel cellulose (to support the proppant), citric acid (to control iron), potassium chloride (to create a brine carrier fluid), ammonium bisulfate (to scavenge oxygen), sodium carbonate (to adjust pH), ethylene glycol (to inhibit scale) and isopropanol (to act as surfactant) among other things.

Behind the water/chemical fluid comes a slurry containing small granules called "proppants"—sand, ceramic beads or bauxite—that lodge themselves in the fissures, propping them open against the enormous subsurface pressure that would otherwise force them shut as soon as the fluid was removed.

The fluid is then drained back out of the well, leaving the fissures and cracks open for oil and gas to flow to the wellbore. Hydraulic fracturing increases the well's effective exposure to the formation, allowing greater production. However, the injection of the fluid is controversial from an environmental standpoint, and the removal of the flowback and produced water requires disposal either by permanent injection into a separate waste injection well or delivery to conventional municipal wastewater disposal systems, or treatment and reuse of the water in oil field operations, such as further fracing.

The technique of hydraulic fracturing, whether in conventional oil and gas fields or shale formations, can implicate the conflicting principles of protection of property rights and groundwater and the full development of natural resources. Hydraulic fracturing results in cracking of deep geological formations, and the horizontal extent of its subterranean impact and recovery cannot be known with 100% certainty for any given well, although micro-seismic logging during the hydraulic fracturing process are now able to provide fairly accurate measurement of the "fracturing length." In the past, this lack of precision has led to claims by adjacent landowners of drainage of subterranean formations by conventional hydraulic fracturing, and in recent years to an increasing number of claims of groundwater contamination allegedly caused by hydraulic fracturing of shale formations. Since 2009, lawsuits alleging groundwater contamination caused by shale fracturing have been filed in Arkansas, Colorado, Louisiana, New York, Pennsylvania, Texas and West Virginia. These cases have either been settled on confidential terms or are still in the early stages of litigation with no reported appellate decisions.

Similarly, the potential rewards and risks of shale gas development give rise to concerns of a "bubble" in the market of shale gas properties and of companies that are involved in exploration and production of shale gas. Also, because no long-term history of shale gas production exists, the size of the reserves and the future feasibility of extracting those reserves may be difficult to predict. Litigation against publicly traded companies by disgruntled investors or of securities enforcement actions by regulators are therefore to be expected.

SECTION 4. ENVIRONMENTAL CONCERNS AND THE RISE OF REGULATIONS

A series of sources—including the movie "Gasland," newspapers (especially The New York Times), academic reports and legal news services—has sparked questions about the risks and costs of using hydraulic fracturing to develop oil and gas shale plays. One result, not surprisingly, is that government responses to hydraulic fracturing are rapidly evolving.

That many such reports have contained errors or been biased is no reason to dismiss all public concern out of hand. Although there still does not appear to be any documented case of the fracturing process itself causing contamination of underground drinking water, combinations of circumstances, sometimes involving inappropriate well installations, have contributed to the presence of natural gas in potable water wells and occupied structures near production sites. Such problems are a particular concern for the industry in places where standards for the installation of residential drinking water wells are lax and uneconomic pockets of shallow hydrocarbons are present outside the production zone, because it is tempting to blame hydraulic fracturing for the manifestation of pre-existing problems. Beyond that, uncontained fracturing fluid spills and well blowouts have caused environmental incidents at the ground surface. And as with other oil and gas activities, production from low permeability formations carries inherent risks of incidental discharges, air emissions, fluid leak-off into the subsurface, and disposal of flowback water and produced water. Fueled by the 2010 Deepwater Horizon well incident in the Gulf of Mexico, the estimated contributions of hydrocarbons to greenhouse gas emissions, and images of residential well water on fire, environmental activists have been doing a good job of tying hydrocarbon production in general, and fracturing in particular, to every real or imagined environmental issue.

The resulting clamor has caused regulators at the federal, State and local levels to re-examine their regulations pertaining to environmental aspects of hydrocarbon exploration and production. The energy industry and state regulatory bodies generally believe that existing and proposed state regulations will be adequate to protect water resources during the development of shale gas fields. On the other hand, a growing contingent of landowners, environmental groups and citizen groups are calling for further investigation of hydraulic fracturing and enhanced regulation, including federal standards, due to concerns about possible drinking water contamination and water usage, among other things.

Among the many ongoing regulatory initiatives relating to fracturing are the following:

• Federal legislation (the "FRAC Act") has been proposed in this area, but faces strong opposition from the industry. If passed in its present form, which at this point seems unlikely, the FRAC Act would repeal an existing provision in the Safe Drinking Water Act that expressly exempts most hydraulic fracturing from underground injecting control ("UIC") permitting obligations and would require the industry to disclose the chemical constituents (but not proprietary chemical formulae) in hydraulic fracturing fluids.⁵
• The US Environmental Protection Agency ("US EPA") appears to be moving slowly but steadily towards fracturing regulation. The agency has (i) launched a study of the water cycle in hydraulic fracturing, especially the potential impacts to drinking water resources, that is expected to be completed in 2014; (ii) concluded that an underground injection permit is required to use fracturing fluid that contains diesel fuel;⁶ (iii) proposed air regulations to require "reduced emissions" during new completions and re-completions of hydraulically fractured gas wells;⁷ (iv) announced a plan to develop standards for discharges to surface water of hydraulic fracturing wastewater; and (v) decided to start working on a proposed rule to gather data on fracturing chemicals and mixtures.
• The US Department of the Interior ("DOI") has been working on fracturing regulations for federal lands that are expected to focus on disclosure of chemical identities, well-bore integrity and management of wastewater disposal.^8,9
• The Delaware River Basin Commission has proposed a comprehensive set of regulations intended to protect water resources within its jurisdiction from any adverse impact due to gas wells.
• Several states have promulgated regulations directed at hydraulic fracturing (often covering disclosure of fracturing substances, permitting, and operational requirements), including: Arkansas, Colorado, Michigan, Montana, West Virginia and Wyoming. In perhaps the most drastic step, New York has suspended most permitting for shale gas drilling pending completion of a review by the New York Department of Environmental Conservation. In 2010, then-governor David Paterson issued an executive order imposing a moratorium specifically on high-volume hydraulic fracturing combined with horizontal drilling, pending the release of a final Supplemental Generic Environmental Impact Statement ("SGEIS") by the New York State Department of Environmental Conservation ("NYSDEC"). NYSDEC has issued a revised draft SGEIS that recommends issuing permits to allow hydraulic fracturing, subject to a variety of operational controls. For example, enhanced well casing would be required in most situations.
• Many local governmental entities likewise have started to regulate or even prohibit the drilling or hydraulic fracturing of oil and gas wells within— and even outside—their jurisdictional boundaries (which raises obvious preemption questions). Local governmental entities in New York and Pennsylvania have been particularly active, but this localized regulatory activity also has occurred in Colorado and Texas. Such restrictions can effectively hinder or prohibit the drilling of wells even where permitted by state regulatory authorities.

All these efforts can be expected to feed upon one another, with one requirement potentially catalyzing development of a new round of regulations elsewhere. The trend therefore is toward increased fracturing regulation.

Even when an operator believes it has followed applicable regulations, it may find itself embroiled in enforcement actions or personal injury lawsuits. In some instances, an operator may even be subject to strict liability, without regard to whether it acted in compliance with law or was negligent. Below are two of the better-known incidents involving non-conventional hydrocarbon production that have resulted in legal claims:

• US EPA Region VI issued a unilateral administrative order to Range Resources after methane, benzene, toluene, ethane, propane and hexane reportedly were detected in drinking water wells near a Range production site in the Barnett Shale in Texas. The Agency directed Range to provide replacement water, survey all nearby drinking water wells, and submit a sampling and investigation plan. Deposition testimony indicated that US EPA did not make a determination of the exact pathway by which contaminants reached the well. Rather, the Agency expected Range to provide that certainty pursuant to the order. Federal enforcement continues, even though the Texas Railroad Commission found that Range was not the source of the contamination.
• Residents of Dimock, Pennsylvania alleged that Cabot Oil and Gas Corporation's nearby Marcellus Shale fracturing and production operations resulted in migration of hydrocarbons, including methane, and other contaminants into their drinking water wells. Under threat of having its statewide operations terminated, Cabot agreed to comply with a State of Pennsylvania order requiring, among other things, restoration or replacement of residential drinking water. Cabot and the State eventually entered a settlement requiring Cabot to offer the 19 families who drew water from the wells payments of twice the value of their homes, install whole-house gas mitigation devices for them as requested, and pay the State $500,000 for its investigation costs. Ultimately, the State concluded that the cause of the problem was faulty well casing. After the State allowed Cabot to stop supplying temporary drinking water, US EPA weighed in, saying the drinking water continues to pose a health risk and promising delivery of an alternative supply, then backtracking by saying more study was needed and withdrawing its offer to supply water, and next flip-flopping again to promise water deliveries to four homes. Meanwhile, affected families are continuing a lawsuit against Cabot that alleges health and property damage.

Pre-existing conditions may complicate responses to such incidents. While today's operators may be targeting deep geologic formations, shallow zones may contain hydrocarbons as well. Extracting them may be uneconomical at present, but they still may end up in people's homes and in groundwater along with other contaminants. For example, a recent study sponsored by The Center for Rural Pennsylvania compared the water quality in 233 groundwater wells within 5,000 feet of Marcellus well pads before and after drilling. No major influences of gas well drilling on water quality were detected, as evidenced by a lack of statistically significant increases in pollutants that are most prominent in drilling waste fluids, such as total dissolved solids ("TDS"), chloride, sodium, sulfate, barium and strontium.¹⁰ There was no increase of dissolved methane levels near hydraulically fractured sites and no correlation between dissolved methane and distance to the nearest Marcellus well. But it bears emphasizing that approximately 24 percent of the groundwater wells contained detectable dissolved methane prior to the nearby drilling activities. The study also found that approximately 40 percent had at least one pre-existing water quality problem (typically an exceedance of drinking water standards for coliform bacteria, turbidity, and/or manganese). In another recent study, an evaluation of more than 1700 water wells prior to proposed gas drilling in northeastern Pennsylvania found that methane was ubiquitous in shallow groundwater and that water wells located in lowland valley areas exhibit significantly higher dissolved methane levels than water wells in upland areas, with no relation to proximity of existing gas wells.¹¹ Investigating whether gas drilling is affecting drinking water in Pavillion, Wyoming, moreover, US EPA found a variety of hydrocarbons in groundwater, the presence of some of which would be consistent with naturally occurring hydrocarbons or releases of refined product. Even a chemical known to be a fracturing additive may be the result of releases from other sources. Press reports are describing US EPA's Pavillion investigation, for example, as having detected 2-butoxyethanol, which has been used in dry cleaning solutions, herbicides, latex paint and home cleaning products, among other things, as well as fracturing fluid.

Significant effort and investigation, meaning significant cost, will be needed to defend a well operator against any allegation that its activities caused groundwater or other impacts separate from pre-existing conditions. The best way of defending against claims arising out of environmental incidents is having a program that prevents them from happening in the first place; the second best is having a strategy in advance for managing the residual risk. In part, this means understanding local conditions sufficiently to demonstrate that a well owner's/operator's operations are not responsible for any alleged problem, and responding promptly when they are.

In putting such plans together for non-conventional hydrocarbon production, compliance with the directly applicable regulations may not be enough. Well owner/operators should consider adopting internal procedures that utilize the "best" parts of industry standards and of regulations from other jurisdictions to go beyond compliance. Here are a few features that might be included, whether or not expressly required:

Baseline environmental surveys

It obviously would be better for a shale well operator to identify problems in drinking water wells and potential pathways to those wells (such as abandoned well bores) before a neighbor alleges poor water quality was caused by recent fracturing. Well-managed surveys, conducted before problems arise, can both insulate an operator from unfounded claims and forestall claims that the surveys were designed, after the fact, to limit liability.

In deciding upon the area to be surveyed, the length of a horizontal well should be considered along with relevant State standards and technical data. In Pennsylvania, for example, the operator of an oil or gas well is presumed to be responsible for the pollution of a water supply that is within 1,000 feet of the well if the pollution occurred within six months after completion of drilling or an alteration. An operator has several potential avenues for rebutting the presumption, including having conducted a pre-drilling or pre-alteration survey showing the contamination to be a pre-existing condition. A Pennsylvania State commission has recommended increasing that distance to 2,500 feet.

As noted above, many substances undesirable in drinking water wells may originate from natural sources. Homeowners (and opponents of fracturing), however, are likely to blame hydrocarbon well drilling, fracturing, or other recent production activities for those pre-existing substances. A baseline environmental study can help mitigate the risks that a well operator and others would be found liable or responsible for contamination in such instances.

Geologic studies that include conditions relevant to environmental analysis

Northeastern Pennsylvania (which includes the town of Dimock) contains gas-bearing and potable water-bearing formations well above the depth of the targeted Marcellus Shale. Various fracture, joint, and fault networks provide pathways for migration and build-up of shallow methane. Driller unfamiliarity with such conditions may contribute to gas migration incidents.

Developing and documenting facts as well installation and operations proceed

Anecdotal evidence suggests that improperly sealed wells, rather than fracturing itself, may be the most likely contributor to cases of water contamination and hydrocarbon migration. Therefore, risk mitigation measures might include designing a cement job that optimizes cement placement, implementing that design, and confirming with up-to-date testing methods that the well is properly designed and constructed to contain hydrocarbons. Such verification then could extend to the fracturing job, followed by checks of well and equipment integrity over time, with documentation at each step along the way.

Designs that minimize environmental risks going forward

The use of more eco-friendly substances is a common way to minimize environmental problems. For hydraulic fracturing, a first step in such a strategy would be to ensure that diesel fuel is not used, since that could be viewed as triggering underground injection control ("UIC") permitting obligations. Another option might be to use the results of any baseline survey to restrict constituents so as to reduce the chances of being enmeshed in arguments about whether fracturing additives commingled with chemicals that originated elsewhere. Consideration also might be given to "environmentally friendly" fracturing fluids based on food-grade chemicals, to the extent available and consistent with operational considerations.

Another focus for design optimization should be surface operations. Fracturing commonly is defended on the grounds that it occurs far below any useable drinking water aquifer underneath impervious geologic zones that are isolated by a sealed well-bore. But, before being injected, fracturing additives are handled at the surface where there may be a direct path to drinking water, and a substantial portion will return to the surface as flowback, or produced, water at the completion of the fracturing along with dissolved constituents from the deep subsurface. Preliminary results from a University of Texas study indicate that many allegations of groundwater contamination arising from shale gas drilling are actually due to aboveground problems rather than hydraulic fracturing. All the effort of designing and implementing a safe fracturing job potentially will be wasted if fracturing chemicals are spilled or leaked onto the ground surface. Measures for reducing the risk of surface problems would include appropriate containment (including use of tanks and impervious berms as practical instead of earthen surface impoundments). Poor design and construction may beget environmentally significant leakage. Drainage and erosion patterns should be considered sufficiently so that natural events do not cause uncontrolled discharges by flooding chemical handling areas (including any impoundments that are used) or undercutting equipment.

Measures to assure problems are quickly identified and fixed

Even the best-laid plans go awry. In managing environmental liabilities, a faster response often limits the extent of the problem. Beyond that, it demonstrates a commitment to being a good neighbor, which can help prevent objections from escalating to public outcry. It makes sense to consider written standard operating procedures covering operations, start-up, shutdown, malfunctions and emergency procedures—all backed up by appropriate oversight. Any emergency response plan should be practical and robust (which is not a synonym for lengthy), customized as appropriate to a particular location, and backed by sufficient training that emphasizes the specific role of each individual in avoiding environmental problems. And, in many cases, addressing landowners' concerns, without admitting liability and even while investigation is ongoing, can reduce hostility.

Drilling and fracturing contracts that are consistent with control programs

The Deepwater Horizon incident provides a large-scale, graphic reminder of what can happen when there are questions about who is supposed to do what. Obligations should be spelled out as plainly as reasonably possible. The well owners/operators must also be aware that they can be found primarily liable in the first instance for the actions of their contractors.

Effective monitoring to ensure compliance with company policy

In the absence of effective procedures to monitor compliance, even the best compliance policies can become a liability rather than an advantage, as deviations from policy can serve to indict even careful operation. As a result, it is critically important that procedures exist to ensure that all operations, including those of drillers and other subcontractors, are conducted in compliance with applicable regulations and policies and that compliance with the monitoring procedures and prompt action on detection of deviations is documented and acted upon appropriately.

However a well owner/operator eventually chooses to manage potential liabilities from non-conventional oil and gas production, the stakes are sufficiently high to make the relevant decisions up front rather than muddling through when problems arise. While conducting operations strictly to applicable regulations often is a successful strategy, consideration of "best practices" for nonconventional production may offer worthwhile benefits. Development of shale oil and gas has relied upon evolving technology; liability management techniques should match.

SECTION 5. DRAINAGE AND CONTAMINATION VIEWED FROM THE RULE OF CAPTURE: AN OLD TOOL APPLIED TO NEW PROBLEMS

Until such time as there is a body of statutory or case law addressing hydraulic fracturing operations, existing law involving analogous operations will necessarily be the starting point for analyzing legal claims of local landowners and leaseholders that are likely to arise from these operations. With the most prolific history of conventional hydraulic fracturing, waterflooding and deep-well injection of industrial waste, Texas has a small, but significant, body of case law that provides a conceptual framework for issues that will likely confront hydraulic fracturing of shale fields.

While other torts such as negligence and nuisance are available, the archetypal hydraulic fracturing case is likely to be based on some aspect of trespass. Because the application (or distinguishing absence) of the so-called "rule of capture" is the guiding principle in these trespass cases, and because the rule of capture is derived from the common law of England and followed by the majority of the states, these cases provide a useful starting point for analyzing trespass-related issues, such as drainage and contamination, that are likely to arise out of shale fracturing.¹² The unrestrained application of the rule of capture was found historically to produce waste, with too many wells being drilled and damage being done to the reservoir. This led to the development of conservation laws that limited the ability of each landowner to drill his own well. Therefore, the companion doctrine of correlative rights was developed to protect landowners/lessees from the effects of the rule of capture in a regulated environment.

Conventional hydraulic fracturing often results in the intrusion of fractures, and possibly the intrusion of the fracturing liquids and proppants, into the subsurface of adjacent property. Subsequent drainage of oil and gas from that same adjacent property may result. The adjacent property owner in such cases may seek to recover for trespass to its subsurface. As shown in the following cases, claims based on drainage of oil and gas from adjacent property will typically be precluded by the "rule of capture," a robust concept that generally overrides the right of a property owner to prevent others from adversely impacting his property. On the other hand, claims based on contamination resulting from the subsurface migration of injected fracturing fluids may not be similarly precluded, although considerable deference will likely be given to regulatory compliance. There are three significant cases from the Texas Supreme Court spanning a period of 49 years that provide a basis for predicting when hydraulic fracturing will likely be immunized from claims by adjacent property owners, and when it likely will not.

The first case, Railroad Commission of Texas et al. v. Dorothy N. Manziel, et al., 361 S.W.2d 560 (Tex. 1962, rehearing denied), does not involve hydraulic fracturing but rather "waterflooding," which is a secondary recovery method by which salt water is injected to drive oil or gas toward other wells. In Manziel, the Texas Supreme Court rejected the attempt of an adjacent mineral rights owner, Manziel, to set aside a Texas Railroad Commission order permitting Whelan's injection of salt water into an "injection well" at an "irregular" interval from the adjoining Manziel lease.¹³ Manziel attacked the order because it permitted Whelan to waterflood too close to Manziel's adjacent lease line which would cause salt water to migrate onto Manziel's lease, ultimately drowning out the hydrocarbon production from her wells.

The evidence showed that due to low reservoir pressure, the best method of recovery for the mature field was waterflooding. In fact, Manziel was herself practicing waterflooding on her own leases, and the salt water injected into one of the Manziel wells had already crossed the boundary of the Whelan lease, forcing oil from the Whelan lease onto other Manziel leases on the opposite side of the Whelan lease. Manziel was attempting to prevent the placement of the Whelan injection well, Eldridge No. 11, at an irregular interval because it would cause more oil under the Whelan lease to be forced back to Whelan wells than would be the case if the injection well was placed at the "regular" setback distance interval of at least 660 feet from the property line.

In granting the order, the Railroad Commission found that the authorization of injection wells at an "irregular" interval was necessary to prevent waste and protect "correlative rights" by encouraging operators such as Whelan to initiate waterflooding and other secondary recovery programs. Manziel conceded that Whelan had the right to protect his lease from drainage, and that the Commission had the power to issue reasonable orders to aid such purpose, including the drilling of wells at "irregular" intervals. However, after conceding this right and power, Manziel asserted that the Railroad Commission could not authorize, nor Whelan carry out, a trespass by injected salt water that would result in loss and injury to her oil and gas interests caused by premature flooding.

The Texas Supreme Court first relied on the general principle that when the Railroad Commission's orders are necessary to prevent waste or to protect correlative rights, the fact that the application of the order will result in loss to some persons does not warrant a finding that there has been a deprivation of property without due process of law. Manziel, 565.

In reviewing the evidence before the Railroad Commission, the supreme court found the following:

The supreme court further found that unless Whelan's Eldridge No. 11 was placed at an irregular interval, the Manziel well would recover five times the amount of oil it would have been able to recover based on the estimated original productive acre-feet of oil beneath the Manziel well as compared to that of the field as a whole. Such disparate recovery would result from drainage from Whelan's lease and would not, therefore, be correlative to Whelan's rights. As a result, the supreme court upheld the Texas Railroad Commission's order on the ground that there was substantial evidence that the exception to the field rules here in question was necessary "to protect the correlative rights of the Whelan Brothers-Vickie Lynn Unit and to prevent drainage from such unit across lease lines to the Manziel Estate's Hollandsworth leases." Manziel, 574.

The Texas Supreme Court found that the Railroad Commission order achieved a proper balance between the common law "rule of capture" and the statutory protection of "correlative rights", Manziel, 572.

The supreme court also addressed Manziel's trespass argument. The court acknowledged that the allegations in Manziel's pleading—that the injection of salt water by Whelan would cause damage to Manziel's well and would result in loss and injury to Manziel's oil and gas interests due to premature flooding—were "sufficient to give rise to the issue of trespass in considering the status of encroaching secondary recovery waters" into Manziel's subsurface. Manziel, 566.

After discussing the importance of secondary recovery and the likelihood of subsurface migration of substances, the supreme court stated,

In support of this non-trespass statement, the supreme court quoted with approval an authoritative treatise for the expansion of the rule of capture to include substances injected for oil and gas recovery:

In recognition of public policy and necessity, the supreme court recognized that the importance of secondary recovery requires, as a practical matter, that the migration of secondary recovery substances not be considered to be trespass,

However, prior to commencing the foregoing analysis of the trespass issue, the supreme court qualified its review of the trespass issue by stating,

Manziel, 566 (emphasis added). The court went on to observe in a similar vein that

Manziel, 568 (emphasis added).

This language and the fact that the Manziel case was an attack on a Railroad Commission order—not a claim against Whelan for damages—limit the significance of the Manziel court's statements concerning non-trespass. This limited construction of the Manziel court's non-trespass holding is re-affirmed in the FPL Farming case, discussed below.

In summary, the Texas Supreme Court in Manziel:

• affirmed the authority of the Texas Railroad Commission to approve recovery measures in order to prevent waste or to protect correlative rights, even when such measures are expected to result in the migration of injected material across lease lines, and
• reserved for the future the question whether the migration of injected material across lease lines constitutes trespass, but did recognize (1) that a finding of trespass in such cases would be incompatible with secondary recovery and the avoidance of waste, and (2) the correlation between the injection of substances that may migrate into the subsurface of others and the rule of capture.¹⁴

While Manziel did not expressly address hydraulic fracturing and its holding is limited as to trespass issues, the 2008 Texas Supreme Court decision in Coastal Oil & Gas Corp. v Garza Energy Trust, et al, 268 S.W.3d 1 (Tex. 2008, rehearing den'd), does address subsurface trespass issues in the context of hydraulic fracturing. In Garza, Salinas owned the minerals in a 748-acre tract known as Share 13. Coastal was the mineral lessee for Salinas' Share 13, and Coastal also owned the minerals on Share 12, adjacent to Share 13. A natural gas reservoir, the Vicksburg T formation, lies between 11,688 and 12,610 feet below these tracts.

Prior to 1993, Coastal drilled successful wells on both its own Share 12 and, as lessee, on Salinas' Share 13. In 1996, Coastal drilled Coastal Fee No. 1 in the northeast corner of Share 12, as close to Share 13 (and the Salinas No. 3) as the Texas Railroad Commission's statewide spacing Rule 37 permitted, 467 feet from the Share 13 boundaries to the north and east.

Subsequently, Salinas sued Coastal for breach of its implied covenants to develop Share 13 and prevent drainage, and for trespass, alleging that Coastal's hydraulic fracturing of Coastal Fee No. 1 invaded the reservoir beneath Share 13, causing substantial drainage of gas from Share 13 (on which Coastal owed Salinas a royalty) to Share 12 where Coastal was both owner and operator, unburdened by any royalty obligation.

The Vicksburg T is a "tight" sandstone formation, relatively impermeable, from which natural gas cannot be commercially produced without hydraulic fracturing. For Coastal Fee No. 1, the "hydraulic length", the distance that the fracturing fluid will travel, was designed to reach over 1,000 feet from the well. (The "propped length" is the slightly shorter distance that the proppant will reach, and the "effective length" is the still shorter distance within which the fracturing operation will actually improve operation.)

The distance from the Coastal Fee No. 1 to the Salinas lease lines was between 467 to 660 feet. The parties agreed that both the hydraulic and the propped lengths exceeded 660 feet, but disagreed as to whether the effective length did. These lengths cannot be measured directly, and each side based its assertion on the opinion of its expert. As measured by the amount of proppant that was injected, the hydraulic fracturing of Coastal Fee No. 1 was "massive" according to Salinas' expert. Salinas' expert further testified that because of the fracing operation on Coastal Fee No. 1, 25-35% of the natural gas it produced drained from Share 13. He explained that he could not be more definite because of two factors that could not be directly ascertained: the exact direction taken by the fractures and the extent of their incursion into Share 13, and whether conditions in the reservoir varied from Share 12 to Share 13. The jury found, among other things, that Coastal failed to reasonably develop Share 13, causing Salinas $1.75 million damages in lost royalties and interest and that Coastal's hydraulic fracturing of Coastal Fee No. 1 trespassed on Share 13, causing substantial drainage and $1 million in lost royalties.¹⁵

The supreme court first addressed Salinas' contention that the incursion of hydraulic fracturing fluid and proppants into another's land two miles below the surface constitutes trespass which can lead to drainage for which the mineral owner can recover damages equal to the value of royalty on the natural gas thereby drained from that land.

In this regard, the court noted that as a mineral lessor, Salinas has only "a royalty interest and the possibility of reverter should the lease terminate", but "no right to possess, explore for, or produce the minerals." The court stated that Salinas' reversion interest in the minerals leased to Coastal is similar to a landlord's reversion interest in the surface estate, and as such, Salinas' claim for trespass seeks redress for a permanent injury to that interest—a loss of value because of wrongful drainage. The court found that Salinas' claim was not speculative; actual, concrete harm was alleged, either in reduced royalty payments or in loss of value to the reversion. The court noted, however, that because Salinas only had a royalty or reversion interest in the minerals, Salinas' claim of trespass would not support nominal damages, (which are damages that do not require proof of an actual loss or injury) but only damages for actual injury. Garza, 9-11.

The supreme court noted that its ruling was narrowed by the fact that Salinas' reversionary interest meant that its trespass claim required proof of the existence of actual injury (rather than being a trespass claim for nominal damages) by stating, "We have not previously decided whether subsurface fracing can give rise to an action for trespass. We need not decide the broader issue here." Having required the existence of actual injury based on the drainage that was caused by the trespass as an element of Salinas' trespass claim, the court then ruled out any actual injury for drainage by invoking the rule of capture, "In this case, actionable trespass requires injury, and Salinas's only claim of injury—that Coastal's fracing operation made it possible for gas to flow from beneath Share 13 to the Share 12 wells—is precluded by the rule of capture." Garza, 11-13.

The supreme court further explained the basis for its ruling: "[The rule of capture] gives a mineral rights owner title to all the oil and gas produced from a lawful well bottomed on the property, even if the oil and gas flowed to the well from beneath another owner's tract. The rule of capture is a cornerstone of the oil and gas industry and is fundamental to both property rights and to state regulations. Salinas does not claim that the Coastal Fee No. 1 violates any statute or regulation. Thus the gas he claims to have lost simply does not belong to him." Garza, 13 (emphasis added).

In recognition of the significance of the "rule of capture" as the basis of its ruling, the supreme court then added, "[Salinas] does not claim that the hydraulic fracturing operation damaged his wells or the Vicksburg T formation beneath his property. In sum, Salinas does not claim damages that are recoverable." Garza, 13. The court then rejected Salinas' argument that the rule of capture does not apply because hydraulic fracturing is "unnatural" by pointing out that

• the very activity of drilling wells is itself unnatural;
• hydraulic fracturing has long been commonplace throughout the industry and is necessary for commercial production in the Vicksburg T and many other formations; and
• the law affords Salinas ample relief, namely himself using hydraulic fracturing to stimulate production from his own wells and drain the gas to his own property—and the right to sue Coastal for not having done so which Salinas had in fact done in this case.¹⁶ Garza, 13.

The supreme court also dispensed with Salinas' argument that stimulating production through hydraulic fracturing that extends beyond one's own property is no different from drilling a slant well that bottoms on another's property, a practice that is unlawful. The court distinguished slant wells by stating, "the rule of capture determines title to gas that drains from property owned by one person onto property owned by another. It says nothing about the ownership of gas that has remained in place. The gas produced through a [slant] well does not migrate to the wellbore from another's property; it is already on another's property." Garza, 13-14.

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Footnotes

1 Translated from, "Cuius est solum eius est usque ad coelum et ad inferos."

2 The permeability of shale is extremely low, 6-9 orders of magnitude less than conventional deposits typically found in more porous sandstones. This permeability is so low that even with modern hydraulic fracturing techniques, the recovery factor of shale deposits is typically less than 1-2%, according to industry sources.

3 Shale Gas Production Subcommittee Ninety Day Report, Secretary of Energy Advisory Board ("SEAB"), US Department of Energy (August 11, 2011), also known as the "Department of Energy Initial Report". 4 Conventional hydraulic fracturing at shallower depths has been practiced by the oil and gas industry since the late 1940s, and includes fracturing for primary production in "tight" sandstone formations and secondary production in older, depleted fields.

5 The Safe Drinking Water Act's ("SDWA's") Underground Injection Control Program governs underground injection activities, including "Class II" wells related to oil and gas production. However, unless diesel fuel is used, hydraulic fracturing is currently expressly exempt from the SDWA. If the FRAC Act passes, the US EPA would be required to promulgate nationwide minimum requirements for hydraulic fracturing activities.

6 US EPA entered into a Memorandum of Agreement in 2003 with several service companies to eliminate diesel fuel from hydraulic fracturing fluids injected into coalbed methane production wells. In 2005, Congress amended the Safe Drinking Water Act expressly to exclude "the underground injection of fluids or propping agents (other than diesel fuels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal production activities" from underground injection control ("UIC") permitting obligations.

7 Regarding air pollution, on July 28, 2011, the US EPA proposed new source performance standards (NSPS) for volatile organic compound (VOC) and methane emissions from certain natural gas operations, specifically including hydraulically fractured wells. According to US EPA, these emissions into the atmosphere offset some of the greenhouse benefits of using natural gas as fuel.

8 While portions of the fracturing industry initially opposed revealing the specific identity of fracturing constituents in order to protect trade secrets, several fracturing specialists have agreed to provide such information, and a number of States have imposed disclosure obligations. The balancing between protection of trade secrets and the public's right to know remains controversial.

9 The Department of Energy Final Report at 5-6. The Shale Gas Subcommittee's Second Ninety Day Report, Secretary of Energy Advisory Board, US Department of Energy (November 18, 2011), also known as the "Department of Energy Final Report" (as distinguished from the Subcommittee's Ninety Day Report known as the "Department of Energy Initial Report" (August 11, 2011)).

10 When the results of the study were first released, it was reported that five of 16 water wells within 2500 feet of drilled sites, and two of 26 water wells within 2500 feet of sites that were both drilled and hydraulically fractured, contained detectable bromide after the production activities, but not before. The researchers have since advised that the lab erred in analyzing bromide concentrations; bromide appeared only in a single well, which also was the one location with an increase in other water quality parameters commonly associated with gas drilling wastes (e.g., TDS, barium, chloride). Follow-up testing at this well 10 months later showed that nearly all parameters, including bromide, largely had returned to pre-drilling concentrations. All of the findings apparently are being reviewed, and a revised report is expected.

11 The researchers also concluded that, on a regional level, elevated methane concentrations in groundwater are a function of geologic features, rather than shale gas development. See L.J. Molofsky et al., Methane in Pennsylvania water wells unrelated to Marcellus shale fracturing, Oil & Gas Journal at 64-67 (December 5, 2011).

12 There are two basic theories in the United States for ownership interests in oil and gas. Texas and other states follow the "ownership in place" theory for oil and gas whereby the landowner has a corporeal possessory interest in oil and gas (similar to "fee simple"), but such ownership is a "determinable fee subject to the rule of capture". Oklahoma and other states follow the "exclusive right to take" theory, where the landowner does not own the oil and gas under his land, but merely retains the "exclusive right to take", a non-corporeal interest. However, the Oklahoma theory also follows the "rule of capture" as set forth in the Garza and Manziel cases discussed in this paper. See Fransen v. Conoco, 64 F.3d 1481, 1491 (Tenth Cir. 1995); Atlantic Richfield Co. v. Tomlinson, 859 P.2d. 1088, 1094-1096 (Okla. 1993); Haymaker v. OCC, 731 P.2d. 1008, 1012 (Okla. 1986); Kuykendall v. OCC, 634 P.2d 711, 716 (Okla. 1981); and Wood Oil Co. v. OCC, 239 P.2d 1023 (Okla. 1950).

13 An "irregular" interval is a distance of less than the 660 feet from the well to the lease line generally required by the Texas Railroad Commission's field rules for the subject field. 14 While Manziel addressed material injected for secondary recovery, there is no apparent reason in principle why materials injected for secondary recovery should be treated differently than material injected for primary recovery operations such as hydraulic fracturing of shale fields.

15 The jury's trespass finding resulted in damages for lost royalty because Coastal leased the minerals on Share 13 from Salinas.

16 The court held, however, that there was no evidence in the record that a reasonably prudent operator should have prevented any portion of the total amount of drainage due to the fracing of the Coastal Fee No. 1. As a result, the court overruled the $1.75 million verdict for failure to reasonably develop Share 13.

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