- Developments to Watch: Shale Appalachian Basin
- April 10, 2018 | Authors: Kevin J. Garber; Blaine A. Lucas; John F. (Jay) Hammond
- Law Firms: Babst Calland - Pittsburgh Office; Babst Calland - State College Office
Driven by demand growth in the industrial and electric generation sectors as well as expanding pipeline and liquefied natural gas export volumes, U.S. natural gas consumption is expected to reach record levels this year. However, production also is forecast to soar to new heights, partly as a result of increasing associated natural gas production in tight oil resource plays.
According to U.S. Energy Information Administration projections, dry natural gas production will increase by 6.7 Bcf a day in 2018, outpacing estimated year-over-year demand growth. Expecting surging supplies to likely translate into relatively low dry natural gas prices for some time, Appalachian Basin natural gas producers continue to work to reduce costs and improve efficiency, while taking advantage of attractive opportunities.
From a business perspective, oil field services remain a primary point of focus for Marcellus and Utica operators in their efforts to reduce costs and improve efficiency, with service providers delivering innovative products to make more productive wells at a lower cost per unit of production. Furthermore, shale gas producers remain focused on consolidating their activities geographically, including selling noncore assets to smaller (often largely debt-financed) operators looking for particular assets less attractive to larger operators (including shallow oil and, in certain circumstances, liquids from shale).
Consolidation continues apace in the shallow conventional natural gas production industry as well. Apart from joint ventures, acreage swaps and other traditional transactions, shale gas producers in the Appalachian region are also pursuing more novel operational strategies to reduce costs and increase profits despite relatively steady natural gas prices. These strategies include new makeup water delivery systems, pad sharing, colocation of facilities and other efforts to reduce duplication of operational outlay.
At the same time, there continue to be significant legal developments in the courts and governmental agencies regarding environmental regulations of the industry. The changing regulatory landscape potentially not only impacts drilling, completion and production activity, but also the development of the midstream and transportation infrastructure that is critical to Appalachian producers’ ability to market their gas production.
Landmark court ruling
In a landmark June 2017 decision, the Pennsylvania Supreme Court rejected a long-standing test for analyzing claims brought under the Environmental Rights Amendment (ERA) of the Pennsylvania Constitution (Article I, Section 27).
In Pennsylvania Environmental Defense Foundation v. Commonwealth, 161 A.3d 911 (Pa. 2017) (PEDF), the Pennsylvania Supreme Court set aside the test from Payne v. Kassab that had been used since 1973, and held that the commonwealth’s oil and gas rights are “public natural resources” under the ERA and that any revenues derived from the sale of those resources must be held in trust and may only be expended to conserve and maintain public natural resources. Essentially, the court replaced a test that had been used for more than 40 years regarding constitutional challenges arising under the ERA with a standard based on the text of the ERA and underlying principles of Pennsylvania trust law.
The court’s decision in PEDF dealt with governmental owned assets, but did not provide a definitive test regarding how the ERA is to be applied in the permitting context. The Environmental Hearing Board subsequently issued two opinions involving the ERA as it applies to environmental permits that examine the record to evaluate whether the Department of Environmental Protection considered the actual or potential adverse effects of the permitted activity on public the environment.
The PEDF case will have significant implications for natural gas exploration and production and pipeline construction in Pennsylvania for the foreseeable future.
In November 2017, DEP announced the details of highly anticipated changes to its air permitting program for the oil and gas industry. DEP released in final draft form two air program general permits: GP-5 and GP-5A, as well as a permit exemption known as Exemption 38. Plans to revise the air permitting framework were first announced in January 2016 as part of Governor Tom Wolf’s Methane Reduction Strategy for Pennsylvania.
The recently updated permits and exemption are not yet in effect or legally binding. DEP intends to finalize the permits and exemption in the first quarter of 2018. Also under discussion is a forthcoming rulemaking to reduce volatile organic compound emissions from existing oil and gas industry sources. DEP has until October 2018 to submit regulations to the U.S. Environmental Protection Agency for approval to meet EPA’s 2016 “control techniques guidelines” that recommend reductions of VOC emissions from equipment and processes used by the oil and gas industry. DEP also is proposing to increase air permit and program fees to address a funding deficit, which is likely to increase the cost of air permitting in the commonwealth.
Government agencies that review energy projects may take a harder look at anticipated greenhouse gas emissions following recent federal court decisions that call for a broader scope of environmental review. In one case from August 2017, a panel of the U.S. Court of Appeals for the District of Columbia circuit vacated a decision by the Federal Energy Regulatory Commission to approve a major interstate pipeline project, holding that FERC did not adequately consider greenhouse gas emissions emitted by burning the natural gas in downstream power plants. In Sierra Club v. FERC, 867 F.3d 1357 (D.C. Cir. 2017), the D.C. circuit faulted FERC’s failure to consider, under the National Environmental Policy Act, what the agency referred to as “speculative analyses” concerning the “relationship between the proposed project and upstream development or downstream end-use.”
The court held that FERC should have either quantified the downstream greenhouse emissions that will result from burning the natural gas being carried by the pipelines, or explained in more detail why it could not be done. This case and others like it present the challenge regarding the question as to what extent climate change should be incorporated into environmental reviews for energy sector projects.
The Marcellus Shale Coalition’s challenge to DEP’s unconventional gas environmental regulations of 2016 (Chapter 78a) is still pending before the Commonwealth Court (MSC v. DEP and Environmental Quality Board, Dkt. No. 573 M.D. 2016). A hearing may be held this summer.
In Ohio, the Ohio Division of Oil & Gas Resources plans to develop draft rules on well spacing, and on oil and gas waste management facilities. The agency is evaluating whether to revise existing well spacing minimum acreage requirements for conventional wells to establish new setback distances for a new horizontal shale well from drilling unit boundaries and other horizontal wells.
For oil and gas waste management facilities, the agency is considering new rules for permitting and operating a facility that stores, recycles, treats, and/or processes brine and other waste associated with oil and gas exploration and production operations, but that is not part of otherwise permitted well operations. These facilities are currently granted temporary authorization by an administrative order.
Local government regulation
The parameters of local government regulation of the oil and gas industry in Pennsylvania continue to be refined and left uncertain by the ongoing judicial fallout from the Pennsylvania Supreme Court’s 2013 decision in Robinson Township v. Commonwealth, 83 A.3d 901 (2013). In Robinson Township, the Supreme Court invalidated two sections of Pennsylvania’s updated Oil & Gas Act (Act 13) that limited the authority of local governments to regulate oil and gas operations. The three-justice plurality decision was based on a reinvigorated interpretation and application of the ERA.
In September 2016, the Supreme Court ruled that the portions of Act 13 giving the Pennsylvania Public Utility Commission and the Commonwealth Court jurisdiction to review local zoning ordinances, withhold impact fee payments and award attorneys’ fees against municipalities were not “severable” from the previously invalidated sections of Act 13, and therefore also were invalid. The implications of Robinson Township in the municipal regulatory arena are currently being considered by the Supreme Court.
In Gorsline v. Board of Supervisors of Fairfield Township, 123 A.3d 1142 (Pa. Commw. Ct. 2015), petition for allowance of appeal granted, 139 A.3d 178 (Pa. 2016), the Commonwealth Court upheld a township’s conditional use approval for an oil and gas well in a residential agriculture (RA) district pursuant to a zoning ordinance’s “savings” or “catch-all” provision. In doing so, the court found that the proposed well was similar to and compatible with other uses permitted in that district, and it rejected Robinson Township-ERA based arguments to the contrary. Although there is no appeal by right, the Supreme Court agreed to take the case. The court heard oral argument in March and a decision is still pending.
While the issues on appeal in Gorsline include casespecific questions concerning the ordinance language and applicable facts, of significance is the Supreme Court’s consideration of whether permitting a shale gas well in a RA district conflicts with Robinson Township. In particular, the question posed is whether natural gas development is an industrial activity that can be permitted only in industrial zoning districts, and therefore, is per se incompatible with agricultural and residential activities.
Although the court’s decision in Robinson Township was viewed as a victory for those advocating local control of oil and gas operations, industry opponents quickly sought to use that plurality decision as a sword to attack the validity of local ordinances permitting industry activity. They argue that these local ordinances violate the ERA because they do not regulate oil and gas development stringently enough, that ordinances cannot permit oil and gas uses in agricultural or residential districts, and that municipalities must engage in extensive environmental assessments when enacting regulations.These Robinson Township arguments are now being supplemented with references to the Supreme Court’s previously discussed 2017 decision in PEDF. To date, zoning hearing boards in a number of municipalities have consistently rejected these types of challenges, as have several county common pleas courts. In June 2017, the Commonwealth Court, in an unpublished opinion, affirmed the validity of one of the challenged ordinances in Delaware Riverkeeper v. Middlesex Township Zoning Hearing Board, 172 A.3d 142 (Pa. Commw. Ct. 2017). The Supreme Court ordered that its consideration of the objectors’ appeal be placed on hold pending its decision in Gorsline.
A case raising similar issues was argued before a three-judge panel of the Commonwealth Court in November 2016. After more than a year of inactivity, the court in January 2018 ordered briefing and oral argument before the full court, directing the parties to address the implication of the PEDF decision (Frederick v. Allegheny Twp. Zoning H’rg Bd., No. 2295 CD 2015 [Pa. Commw. Ct. Jan. 3, 2018]).
Pipeline safety regulations
Having recently filled the two most important political appointments at the U.S. Department of Transportation’s Pipeline & Hazardous Materials Safety Administration (PHMSA), the Trump administration appears ready to take further action on two rulemaking proceedings that could reshape the nation’s federal safety standards for hazardous liquid and natural gas pipelines.
On October 30, Howard R. Elliott was officially sworn in as PHMSA’s administrator. Elliot brings more than four decades of experience in the freight rail industry to his new position, including expertise in the areas of hazardous material safety and security.
A few months earlier, on August 7, Drue Pearce became PHMSA’s deputy administrator. Pearce previously served as an official in the George W. Bush administration and as a state legislator in Alaska. As the core of the agency’s new leadership team, Elliot and Pearce will play an important part in deciding the fate of a significant gas pipeline safety rulemaking proceeding that PHMSA initiated during the previous administration.
In April 2016, PHMSA issued a notice of proposed rulemaking (NPRM) proposing extensive changes to the safety standards and reporting requirements for gas transmission and gathering lines. To address certain mandates in the 2011 reauthorization of the Pipeline Safety Act and related National Transportation Safety Board safety recommendations, PHMSA proposed new requirements, including:
Verifying the maximum allowable operating pressure and documenting the materials in onshore steel gas transmission lines;
New requirements for conducting integrity assessments of certain transmission lines in moderate consequence areas; and
New corrosion control, pipeline repair and recordkeeping requirements, as well as changes to the integrity management requirements for gas transmission lines.
In addition to the proposals for gas transmission lines, PHMSA proposed significant changes to the regulations for onshore gas gathering lines, primarily to address the growth of new pipeline infrastructure in the nation’s shale plays. The proposed changes included new definitions for determining what qualifies as an onshore gas gathering line, new safety standards for regulated onshore gas gathering lines (which would apply to certain historically exempt onshore gas gathering lines in rural locations), and new reporting requirements for all gas gathering lines, whether regulated or not.
The pipeline industry responded by expressing significant concerns with many of the proposals in the NPRM. For example, the American Petroleum Institute submitted an economic analysis showing that PHMSA made numerous errors in developing the preliminary regulatory impact analysis for the NPRM.
API’s economic analysis also showed that PHMSA overestimated the benefits of the proposed rules by $2.9 billion to $3.1 billion and underestimated the potential costs by $32.8 billion. Despite the pipeline industry’s concerns, PHMSA held an initial meeting of the Gas Pipeline Advisory Committee (GPAC), the federal advisory committee that reviews its gas pipeline rulemaking proposals, to begin considering the NPRM’s proposals in January 2017. PHMSA held two subsequent GPAC meetings in June and December 2017 and has scheduled a series of additional meeting for March and June 2018.
According to the Department of Transportation’s latest significant rulemaking report, PHMSA expects to issue a final rule in August 2018. That schedule assumes PHMSA will present the final rule to the secretary’s office for consideration in March, a development that seems highly unlikely given the current pace of the GPAC’s review of the NPRM.