In 1859, “Colonel” Edwin L. Drake struck oil near Titusville, Pennsylvania, an event that launched America’s oil and gas industry. Since that time, more than 350,000 oil and gas wells have been drilled in the Keystone State. Pennsylvania boasts several significant oil and gas basins, including the Devonian (Ohio), Utica, and Marcellus Shale Formations. The geology of the Marcellus Shale and drilling trends suggest that areas in the southwest, north-central, and northeastern regions of Pennsylvania may be especially productive. Its richest layers are found between 5,000 and 8,500 feet below the ground—depths once believed to be prohibitively expensive to access—but recently have attracted immense interest because of advances in drilling technology and natural gas extraction.
Statutory and Regulatory Framework
Pennsylvania first adopted legislation relating to oil and gas drilling in the Commonwealth’s Oil and Gas Act of 1984. The Pennsylvania Department of Environmental Protection (DEP) has enacted more extensive rules and regulations, found in Chapter 78 of the Pennsylvania Code. DEP also enforces the Commonwealth’s various environmental protection laws, including the Clean Streams law, the Dam Safety and Encroachments Act, the Solid Waste Management Act, the Water Resources Planning Act, and the Community Right to Know Act.
With respect to oil and gas leases, Pennsylvania does not audit payments or read or calibrate meters or tanks. However, in 1979, the Pennsylvania Legislature passed the Guaranty Minimum Royalty Act, which mandates that landowners receive a 12.5% royalty on any oil or natural gas drilled on their property. In recent years, Pennsylvania courts have addressed the propriety of various royalty calculation methods and other contractual mechanisms to determine if leases in the state comply with the 12.5% minimum royalty requirement. In recent years, several Pennsylvania legislators have introduced bills that would attempt to clarify the current 12.5% minimum royalty requirement, particularly with respect to the incurrence of post-production costs. The latest such effort, H.B. 1708, was referred to the Environmental Resources and Energy Committee in August 2017 and remains pending.1
In addition, two federal interstate compact commissions—the Susquehanna River Basin Commission (SRBC)2 and the Delaware River Basin Commission (DRBC)3 —have authority over specified water uses within their basins, which cover parts of Pennsylvania.4 The SRBC and DRBC regulate the rate and volume of water withdrawals within their river basins. Those operators who must submit plans per SRBC and DRBC requirements may utilize those plans to satisfy this requirement but must still formally apply to DEP.
Recent News and Developments
Current Drilling Restrictions and Moratoria
The DRBC established a de facto moratorium on drilling in Pennsylvania’s Wayne and Pike counties in 2010 pending DRBC regulations for oil and gas development in those counties.5 The DRBC initially proposed regulations in early November 2011, and intended to vote on the proposals in November 2011. However, the DRBC cancelled the meeting and the vote after strong opposition from New York and Delaware state officials. On November 30, 2017, the DRBC published a proposed rule that, if finalized, would prohibit “high-volume hydraulic fracturing” within the Delaware River Basin. The proposed rule reflects the DRBC’s conclusion that “high-volume hydraulic fracturing poses significant, immediate and long-term risks to the development, conservation, utilization, management, and preservation of the water resources of the Delaware River Basin.” The DRBC held a series of public hearings on the proposed rule beginning in January 2018,6 but, as of September 2018, has yet to issue a final rule.
In May 2016, a Wayne County, Pennsylvania operator filed suit in federal court challenging the DRBC’s jurisdiction over natural gas extraction activities.7 The suit was dismissed in March 2017 after a U.S. District Court judge held that the DRBC had jurisdiction over projects, such as natural gas extraction, that involve water resources in the Basin.8 The operator appealed, and, in July 2018, the U.S. Court of Appeals for the Third Circuit overturned the lower court’s dismissal and remanded the case for further fact-finding.9 Specifically, the Third Circuit found that the definition of a “project” under the Delaware River Basin Compact was ambiguous.10
In January 2015, Pennsylvania Governor Tom Wolf signed an executive order (2015-03) that reinstated a 2010 moratorium on future oil and gas development in state parks and forest land.11 The moratorium applies exclusively to land currently unavailable for development. Prior to the 2010 moratorium, the state’s Department of Conversation and Natural Resources (DCNR) had leased more than 673,000 acres of state forest land for development out of the approximately 1.5 million acres underlain by the Marcellus and other shale gas formations.12
Act 13: the Impact Fee Law
Pennsylvania’s Act 13 of 2012 (Act 13) established a state-wide approach to regulating increased oil and gas drilling and hydraulic fracturing activity. 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 formations 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 using hydraulic fracturing or multilateral well bores.
Notably, Act 13 provides for: 1) new well fees to be assessed and collected on unconventional wells; 2) a formula for distribution of these fees; 3) substantial revisions to environmental protections for both surface and subsurface activities; and 4) restrictions on the authority of local governments to impose burdens on oil and gas activities beyond those required by the state or those imposed upon other commercial and industrial activities. Act 13’s new environmental provisions include increased setback requirements for unconventional gas development and enhanced protection of water supplies, including water management plans.
In December 2013, however, the Pennsylvania Supreme Court issued a sharply divided, but sweeping opinion13 invalidating important portions of Act 13 that sought to preempt local regulation of oil and gas development in favor of a comprehensive approach implemented by the state legislature. A plurality of the Supreme Court based its decision on the Pennsylvania Constitution’s “Environmental Rights Amendment,” which provides, in part, that the people of Pennsylvania “have a right to clean air, pure water, and to the preservation of the natural, scenic, historic and esthetic values of the environment.”14 The plurality decision concluded that “several core provisions of Act 13 violate the Commonwealth’s duties as trustee of Pennsylvania’s public natural resources under the Environmental Rights Amendment.”15 The remaining justice in the majority found Act 13 to be unconstitutional based on substantive due process.16 Additional controversy and legal challenges to various aspects of Act 13 have continued in recent years. For example, the Pennsylvania Independent Oil and Gas Association argued that the decision prevents state regulators from enacting tougher regulations governing surface operations at and around drilling sites.17 In particular, the industry groups contend that DEP lacks authority to set regulations governing “species of special concern” that might be affected by drilling. Industry groups have also objected to DEP’s proposed regulations requiring drillers to improve the quality of water wells beyond their initial condition. They say such actions unreasonably impact conventional oil and gas well operations without a compelling environmental justification.
Chapter 78 and Chapter 78(a) Regulations
In April 2011, DEP and the Oil and Gas Technical Advisory Board began a rulemaking process that proposed wide-ranging revisions to Chapter 78 drilling regulations for unconventional oil and gas wells. As a general matter, the proposals addressed four types of issues: (1) permitting requirements related to the protection of public resources; (2) requirements to identify and monitoring of orphaned and abandoned wells; (3) wastewater storage and containment practices at or near the drilling site; and (4) protection of wetlands, streams, and drinking water resources. In December 2013, DEP opened a 90-day public comment period that drew more than 24,000 public comments.
In addition, the Pennsylvania General Assembly passed Act 126 in July 2014, which requires DEP to promulgate separate regulations for conventional and unconventional wells under Chapter 78 and Chapter 78(a), respectively.
The Chapter 78(a) regulations were finalized on October 8, 2016. Chapter 78(a) aims to enhance surface water protections by requiring that if the proposed limit of disturbance associated with an unconventional well is within 100 feet of any watercourse, any high quality or exceptional value body of water, or any wetland greater than 1 acre in size, the permit applicant must demonstrate that the well site location will protect the watercourse or bodies of water. Chapter 78(a)also codifies anti-degradation requirements for unconventional operations located in a special protection watershed. Additionally, while unconventional well operators were already required to replace or restore a water supply that was degraded by oil and gas development, Chapter 78(a)specifies that the restored or replaced supplies must meet the standards in the Pennsylvania Safe Drinking Water Act or be comparable to the quality of the water supply before it was affected if that water was of a higher quality than the standards require.
Chapter 78(a)also enhances requirements applicable to unconventional operators for reporting and remediating spills and releases of regulated substances. A spill or release must be reported to the DEP when: 1) the spill or release causes or threatens pollution of state waters; or 2) a spill or release of 5 gallons or more of a regulated substance over a 24-hour period is not completely contained by secondary containment. The operator or other responsible party must then remediate a release in accordance with one of two options, depending on the nature of the spill.
Under Chapter 78(a), temporary aboveground storage structures of greater than 20,000 gallon capacity must be approved by DEP prior to being used. DEP must be given notice prior to the installation of these structures at an unconventional well site, and the structures must be removed within 9 months of drilling completion.
Chapter 78(a)also prohibits the use of open top structures or pits to store brine and other production fluids at an unconventional well site. The rules further require that tanks used to store production fluids at unconventional well sites must be equipped with secondary containment and must satisfy certain performance and technical standards. Heightened standards also apply to the use of underground or partially buried storage tanks to store brine or other fluids produced during the life of an unconventional well.
Finally, Chapter 78(a)codifies for unconventional well sites DEP’s current approval process for onsite oil and gas wastewater processing. Under the rules, unconventional well operators may process fluids generated by oil and gas wells at the site where the fluids were generated or at the site where the fluids will be beneficially used for permitted oil and gas activities with approval from DEP. An operator processing fluids onsite must develop a radiation protection action plan and procedures for training, notification, recordkeeping and reporting to be implemented at the site. These plans do not require DEP approval, and the same plan may be used at multiple well sites if the conditions are similar and notification is provided in advance to DEP.
Chapter 78(a)became effective immediately upon publication, but, shortly afterward, industry filed a legal challenge.18 In August 2018, an en banc panel of the Pennsylvania Commonwealth Court upheld provisions of the Chapter 78 regulations requiring prospective drillers to provide notification when a proposed well might impact certain publicly-accessible areas.19 However, the court’s ruling limited the triggers to the notification requirement, excluding proposed wells near common areas of a school property, playgrounds, or areas that might impact species of “special concern.”20 Legal challenges to six other Chapter 78(a) provisions remain pending,21 and, aside from provisions relating to in-ground impoundments and post-treatment remediation of well sites, remain subject to a preliminary injunction.22
Revised General Permits Regulate Methane Emissions from Unconventional Natural Gas Wells
On June 9, 2018, DEP released revised versions of General Plan Approval and/or General Operating Permits GP-5 and GP-5A (together, the “Revised General Permits”), applicable to “Natural Gas Compression Stations, Processing Plants, and Transmission Stations” and “Unconventional Natural Gas Well Site Operations and Remote Pigging Stations,” respectively. The Revised General Permits are aimed principally at regulating methane emissions from unconventional natural gas wells and midstream facilities, consistent with Governor Tom Wolf’s four point plan for reducing methane emissions announced in January 2016. The Revised General Permits are available to facilities with actual emissions less than 100 tons per year (“tpy”) of criteria pollutants (NOx, CO, SO2, PM10, and PM2.5), less than 50 tpy of volatile organic compounds (“VOCs”), less than 10 tpy of any single hazardous air pollutant (“HAP”), and less than 25 tpy of total HAPs (use of the Revised General Permits is further restricted in Philadelphia, Bucks, Chester, Montgomery, and Delaware Counties to facilities with less than 25 tpy each of NOx and VOC emissions).
The Revised General Permits, which apply to new and modified sources constructed on or after August 8, 2018, require compliance with federal New Source Performance Standards such as 40 C.F.R. Part 63 Subparts OOOO and OOOOa, although EPA has proposed a temporary stay of some of the OOOOa requirements, but also include more stringent requirements as well. Specifically, the Revised General Permits contain “Best Available Technology” (“BAT”) standards that apply in addition to federal New Source Performance Standards. Of the thirteen BAT determinations in the GP-5 permit, nine impose requirements more stringent than the federal New Source Performance Standards; eight of the eleven BAT determinations in the GP-5A permit are more stringent than federal New Source Performance Standards. Most notably, the Revised General Permits include a 200 tpy limit on methane emissions above which a BAT requirement for methane control applies—the first such numeric threshold applicable to methane emissions from unconventional natural gas wells and midstream facilities.
Pennsylvania Superior Court Allows Trespass Claim Related to Hydraulic Fracturing
In April 2018, a three-judge panel from the Pennsylvania Superior Court issued a published opinion in Briggs, et al. v. Southwestern Energy Production Co. holding that the traditional rule of capture “does not preclude liability for trespass due to hydraulic fracturing.”23 The panel reasoned that “[p]recluding trespass liability based on the rule of capture would effectively allow a mineral lessee to expand its lease by locating a well near the lease’s boundary line and withdrawing natural gas from beneath the adjoining property, for which it does not have a lease.”24 Plaintiffs in Briggs are landowners who allege that unconventional gas wells drilled pursuant to a lease on a neighboring property constitute a “past and continuing trespass” on plaintiffs’ property.25 The trial court granted summary judgment in favor of the operator, holding that the rule of capture precluded any recovery by plaintiffs.26 Pursuant to the Superior Court’s April 2018 opinion, the trial court’s order granting summary judgment to the operator has been reversed, and the case has been remanded to the trial court for further proceedings.27 In June 2018, the operator sought an en banc rehearing before the Pennsylvania Superior Court, but that request was rejected.28 In July 2018, the operator filed a petition with the Supreme Court of Pennsylvania seeking review of the Superior Court’s decision.29
On February 17, 2017, DEP published a report concluding that four specific low-magnitude seismic events that occurred on April 25, 2016 “were likely correlated” with hydraulic fracturing activity. The seismic events at issue were registered on the Pennsylvania Seismic Network and consisted of a series of four “microseismic events” at magnitudes unlikely to be noticed by humans. The report concludes that these seismic events showed a “marked temporal/spatial relationship” to hydraulic fracturing activities at a nearby well pad, but ultimately cautions that “there is no definitive geologic association of events at this time.”
Nonetheless, DEP’s report includes several recommendations that will likely have an impact on how operators conduct their fracturing activities in certain areas of the Utica Shale formation. The technique used at the time of the April 2016 seismic activity is called “zipper fracturing,” and involves conducting hydraulic fracturing operations concurrently at two horizontal wellbores that are parallel and adjacent to each other. The DEP report describes that DEP and the operator agreed to a seismic monitoring plan in November 2016 that requires the operator of the well at issue to (i) discontinue the use of the “zipper fracturing” technique during any future completions when there is less than a quarter mile between lateral portions of adjacent wellbores; (ii) maintain its own seismic network to detect events; and (iii) adopt a specific seismic reporting and response plan. The plan also requires the operator of the well at issue to abide by a “traffic light” system, whereby the operator must, among other things, (i) notify DEP of seismic activity above 1.0 magnitude within 6 miles of a wellbore path; (ii) suspend operations if three seismic events between 1.5 and 1.9 magnitude occur within three consecutive days within 3 miles of a wellbore path; and (iii) shut down well operations if a seismic event magnitude 2.0 or greater occurs within 3 miles of a wellbore path. The report recommends that other operators in North Beaver, Mahoning, and Union Townships in Pennsylvania follow similar plans.
The report’s “traffic light” system recommendations are particularly notable because they apply at conservative levels of seismicity compared to other jurisdictions. For example, Well Completion Seismicity Guidance applicable to operators in the Scoop and Stack plays published by the Oklahoma Corporation Commission in December 2016 requires reporting of seismicity at magnitude 2.5 or greater within 1.25 miles of fracturing operations, a temporary pause in operations at magnitude 3.0 or greater, and the suspension of operations at magnitude 3.5 or greater.
Several local governments in the Pittsburgh area have taken steps to regulate seismic testing.30 Specifically, South Fayette, Oakmont, and Monroeville have each adopted ordinances requiring seismic testing.31 Monroeville’s ordinance, which was adopted in September 2017, also requires a local permit, a $500,000 performance bond, $2 million in general liability insurance, and notifications to nearby property owners.32
Proposed Unconventional Well Permit Fee Increase
In July 2018, DEP published a proposed rulemaking which would increase the application fee for an unconventional well permit from $5,000 to $12,500. DEP representatives have argued that the proposed increase in fees is necessary to cover the costs of its DEP Oil and Gas Management Program, which is responsible for issuing permits and overseeing health and safety regulations.34
A public comment period on the proposed rulemaking closed on August 13, 2018, but the rulemaking has yet to be finalized as of September 2018.35
Local Zoning Restrictions and Pennsylvania’s Environmental Rights Amendment
In recent years, local zoning laws have been at the center of litigation related to hydraulic fracturing operations in Pennsylvania. For example, environmental groups challenged 2016 revisions to Middlesex Township’s zoning code allowing oil and gas development in residential/agricultural districts.36 The Pennsylvania Commonwealth Court upheld the revisions to the zoning ordinance, noting that the zoning code had already allowed the construction of public utility structures that were “similar and compatible with” oil and gas well site development.37 More recently, a non-profit organization has challenged Penn Township’s zoning ordinance, which allows hydraulic fracturing wells in areas zoned both industrial and rural; the group contends that such activity should only be allowed in industrial zones.38 In another recent case, the Pennsylvania State Supreme Court held that the Fairfield Township Board of Supervisors erred in permitting oil and gas development in a residential/agricultural district as a “public service facility.”39 However, legislative amendments to the township’s zoning code could allow oil and gas development in any or all of the township’s zoning districts.40
A recent Pennsylvania Supreme Court decision could provide future legal challenges similar to those outlined above with a constitutional basis to overturn government actions.41 In June 2017, the Pennsylvania Supreme Court issued an opinion holding that Article 1, Section 27 of the Pennsylvania Constitution—the Environmental Rights Amendment—sets forth a standard pursuant to which the state must abide as a trustee of public natural resources.42 The court threw out a decades-old balancing test used to determine compliance with the Environmental Rights Amendment in holding that the state’s use of money from leasing public land for gas drilling to close a budget gap ran afoul of the constitutional provision.43 While it is likely to take years of litigation for litigants and governments to understand precisely how courts will interpret the Environmental Rights Amendment going forward, commentators have suggested that the June 2017 opinion may be “the biggest environmental decision in the state in decades and a harbinger of a new and uncertain era of scrutiny for projects with potential impacts on natural resources.”44
Last updated September 2018.