Friday, February 16, 2018

Global Shale Law Compendium: Shale Law Governance in Michigan


Written by Chloe Marie – Research Fellow

The Global Shale Law Compendium series addresses legal developments and other issues related to the governance of shale oil and gas activities in various countries and regions of the world. In this article, we will focus to legal, policy, and governance issues related to shale gas development in the United States, and more specifically in the state of Michigan.

The state of Michigan holds significant oil and natural gas fields and development has been focused on Michigan’s northern Lower Peninsula. According to the U.S. EIA, the Antrim Gas Field, located in the northern Lower Peninsula, is one of the top 100 natural gas fields in the country and ranked 29th for proved reserves. The Antrim Gas Field also is home to approximately 1 Tcf of shale gas resources.

The technique of hydraulic fracturing is not new in Michigan as it was first used in 1952. Since that time, the Oil, Gas, and Minerals Division (OGMD) within the Michigan Department of Environmental (DEQ) has granted permits to hydraulically fracture approximately 12,000 wells. According to the DEQ’s map identifying high volume hydraulic fracturing activities, 39 wells have utilized the technique since 2008.  The largest cluster of wells is in Kalkaska County.

Numerous energy companies have shown interest in developing the Collingwood Shale, also located in Michigan’s northern Lower Peninsula. A subsidiary of Encana Corporation drilled its first exploratory well in 2010 in Missaukee County, which well later produced about 2.5 million cubic feet of shale gas per day for a period of 30 days. Based on the production levels and falling natural gas prices, Encana’s subsidiary decided to step aside from shale gas development in the area in 2014 to focus on projects more economically viable outside Michigan.

In Michigan, oil and gas activities, including the use of hydraulic fracturing, are governed primarily by Part 615 and Part 617 of the Natural Resources and Environmental Protection Act of 1994. Under this Act, the Michigan DEQ OGMD is responsible for overseeing the oil and gas permitting process.

A well operator is required to submit a permit application to OGMD and must comply with additional requirements when seeking to use hydraulic fracturing. These additional requirements include providing a list of all chemical compounds to be used in a high volume hydraulic fracturing operation. Applicants must make publicly available information on all chemical additives used during hydraulic fracturing through the FracFocus Chemical Disclosure Registry.

In addition, any permittee is required to file a special request with OGMD in order to withdraw a large volume of water for hydraulic fracturing using the Michigan Water Withdrawal Assessment Tool (WWAT). The regulations also require anyone involved in high volume hydraulic fracturing to develop a plan for the baseline sampling of water wells.

Wednesday, February 14, 2018

Shale Law in the Spotlight: UPDATE – Current Legal Developments Relating to Bureau of Land Management (BLM) Rules on the Methane Waste Prevention and Hydraulic Fracturing


Written by Chloe Marie – Research Fellow

·         Update on BLM Methane Waste Prevention rule

On December 8, 2017, the Bureau of Land Management (BLM) issued a final rule, the purpose of which is to “temporarily suspend or delay certain requirements” provided for in the Waste Prevention, Production Subject to Royalties, and Resource Conservation rule – also known as the Methane Waste Prevention rule. More precisely, the Methane Waste Prevention rule now will not become effective until January 17, 2019. This most recent final rule follows the publication by BLM of a proposed rule in the Federal Register on October 5, 2017.

The Methane Waste Prevention final rule was published on November 18, 2016, as part of President Obama’s Climate Action to further tackle U.S. methane emissions. This rule provided for a new set of regulations designed to help curb methane emissions released through venting or flaring during oil and gas operations carried out on Federal and Indian lands.  In a Presidential Executive Order No. 13783 dated March 28, 2017, the White House directed Secretary of Interior Ryan Zinke to review the Methane Waste Prevention rule as part of a plan to reduce regulation that would limit energy development and production. BLM was then commissioned to conduct an initial review of the rule.

From this initial review, BLM raised “concerns regarding the statutory authority, cost, complexity, feasibility, and other implications of the 2016 final rule, and therefore wants to avoid imposing temporary or permanent compliance costs on operators for requirements that might be rescinded or significantly revised in the near future.” BLM also declared that it would work on a proposed revision of the 2016 rule in order to comply with the priorities expressed in the Executive Order mentioned above.

On December 19, 2017, a number of environmental groups brought legal action against the Secretary of Interior before the U.S. District Court for the Northern District of California challenging BLM’s decision to suspend or delay certain requirements provided for in the Methane Waste Prevention rule (Sierra Club et al. v Ryan Zinke et al., No. 3:17-cv-07186). The environmental groups argue that such decision “creates a regulatory and policy vacuum that BLM concedes will decrease the amount of natural gas brought to market by [9 bcf]” before adding that “this will result in a reduction in royalties and will have harmful impacts on public health and the environment by increasing emissions of methane … and other air pollutants.” As a result, they are seeking an order vacating such decision and reinstating all provisions of the 2016 Methane Waste Prevention rule.  

·         Update on BLM Hydraulic Fracturing rule

On December 29, 2017, BLM issued a final rule repealing the Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands rule that initially was published in the Federal Register on March 26, 2015. The purpose of the Hydraulic Fracturing rule was to amend existing requirements for oil and gas operations on Federal and Indian lands and set stringent regulations relating to wellbore integrity, water quality protection, and public disclosure of chemicals used during hydraulic fracturing operations. The Hydraulic Fracturing rule was scheduled to become effective on June 24, 2015; however, implementation of the rule was delayed amid judicial and regulatory challenges.

As with the Methane Waste Prevention rule, Secretary of Interior Ryan Zinke was instructed to examine whether the Hydraulic Fracturing rule was consistent with the policies established in section 1 of Executive Order No. 13783. Subsequently, Secretary Zinke ordered the repeal of the 2015 rule following its review.

In the 2017 final rule, BLM explains that this rescission is needed because the original Hydraulic Fracturing rule would have “impose[d] administrative burdens and compliance costs that are not justified.” BLM also declared that it “believes that the appropriate framework for mitigating these impacts exists through state regulations, through tribal exercise of sovereignty, and through BLM’s own pre-existing regulations and authorities.”

Following the release of this rescission rule, the state of California initiated legal proceedings against BLM on January 24, 2018. The state of California is asking the U.S. District Court for the Northern District of California to vacate the rescission rule and reinstate all provisions of the 2015 Hydraulic Fracturing rule. California also alleges that “by repealing the Fracking Rule in its entirety, Defendants have tossed aside the public interest in ensuring that fossil fuel development is conducted in an environmentally sound and safe manner in service of what their own data shows is a negligible increase in oil and gas operators’ profits.” Stay tuned for further legal developments.

Monday, February 12, 2018

The Shale Law Weekly Review - February 12, 2018

Written by:
Jacqueline Schweichler - Education Programs Coordinator
Tori Wunder - Research Assistant

The following information is an update of recent local, state, national, and international legal developments relevant to shale gas.

Pipelines: DEP Imposes Penalty and Allows Sunoco to Resume Work on Mariner East 2
On February 8, 2018, the Pennsylvania Department of Environmental Protection (DEP) filed a Consent Order and Agreement with Sunoco Pipeline, L.P. (Sunoco) allowing work to resume on the Mariner East 2 pipeline.  The order imposes a $12.6 million civil penalty on Sunoco for permitting violations. In January, DEP ordered Sunoco to suspend all work after drilling fluids were discharged without a permit. In addition, Sunoco failed to obtain permit authorization prior to conducting horizontal directional drilling activities. The Mariner East 2 is a 20-inch pipeline project that expands the capacity of the current Mariner East 1 to 345 thousand barrels per day of natural gas liquids.

Pipelines: Immediate Access to Disputed Properties Granted to MVP 
On February 2, 2018, a federal judge in West Virginia granted Mountain Valley Pipeline, LLC (MVP) immediate access to disputed lands along the path of the Mountain Valley Pipeline (MVP v. Simmons, et al., 1:17-cv-00211). The court states that in order to access the disputed properties, MVP must deposit certified checks and post surety bonds worth several times more than the appraised easement value. The court concluded that MVP has met eminent domain requirements and is authorized to immediately access the properties. The determination was based upon MVP’s showing that it would be “irreparably harmed in the absence of a preliminary injunction,” that this harm is not outweighed by the concerns of the defendants, and that granting access is in the public interest.

Pipelines: FERC Allows Rover Pipeline to Continue Drilling Under Tuscarawas River
On February 6, 2018, the Federal Energy Regulatory Commission (FERC) approved the revised drilling plan submitted by Rover Pipeline, LLC (Rover) and issued an order authorizing Rover ro recommence drilling at the Tuscarawas River. FERC ordered Rover to cease drilling at the end of January after drilling fluid was lost.  Rover was asked to submit information on how they planned to address drilling fluid losses. In addition, Rover was told to provide a revised drilling plan with a feasibility analysis of alternate crossing locations at the Tuscarawas River. The Rover pipeline is designed to transport 3.25 bcf/d of Marcellus and Utica shale natural gas along 713 miles of pipeline.

Oil and Gas Leasing: Lawsuits Filed Against BLM for Alaskan Oil and Gas Lease Sale
On February 2, 2018, two lawsuits were filed by several environmental and conservation groups against the Bureau of Land Management (BLM) for petroleum lease sales in northern Alaska. The first lawsuit, filed by Earthjustice, alleged that BLM failed to fulfill its obligations under the National Environmental Policy Act (NEPA) in 2016 and 2017 when it held oil and gas lease sales in the National Petroleum Reserve - Alaska (Natural Resources Defense Council, et al. v. Ryan Zinke, et al.) In the complaint, the plaintiffs allege that BLM acted arbitrarily and capriciously by foregoing NEPA analysis, and the plaintiffs request that the 2016 and 2017 be vacated. The second lawsuit was filed by several groups including the Alaska Wilderness League, the Northern Alaska Environmental Center, and The Wilderness League. In this lawsuit the plaintiffs also allege that BLM violated NEPA during the 2016 and 2017 oil and gas lease sale.

Pipelines: FERC Files New Environmental Impact Statement for Southeast Market Pipeline Project
On February 5, 2018, the Federal Energy Regulatory Commission (FERC) filed a new Final Environmental Impact Statement (EIS) for the Southeast Market Pipelines Project (Project). The new EIS was filed in response to a court order issued in August 2017. In the court order, the judge stated that the initial EIS was inadequate because it did not contain sufficient information on the greenhouse gas emissions that would occur as a result of pipeline use.  The Project is comprised of three natural gas pipelines including the Sabal Trail Project, the Florida Southeast Connection, and Transcontinental Gas Pipe Line Company LLC’s Hillabee Expansion Project.

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See our Global Shale Law Compendium and this week’s article,
Shale Governance in the Netherlands


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Friday, February 9, 2018

Global Shale Law Compendium: Shale Governance in the Netherlands

Written by Chloe Marie – Research Fellow

The Global Shale Law Compendium series addresses legal developments and other issues related to the governance of shale oil and gas activities in various countries and regions of the world. In this article, we will highlight governance actions taken by the Netherlands to develop policies specific to shale gas development. 

The Groningen Gas Field located in the north of the Netherlands was first discovered in 1959 and is home to the largest reserves of natural gas in Europe. In recent years, due to the depletion of natural gas reserves in this Field, the Dutch government has demonstrated some level of interest in developing the country’s potential shale gas reserves. Following a lengthy process of study and investigation, however, the government has decided to forego development at this time.

In 2009, the Dutch Ministry of Economic Affairs – responsible for issuing well drilling permits – awarded a certain number of permits in order to carry out shale gas exploration in the provinces of Brabant and Flevoland. The Dutch government, however, encountered resistance from opposing political parties, several NGOs, and the general public who were concerned over the impacts of shale gas development on the environment and public safety. In 2011, amid rising tensions surrounding such development, the Dutch Ministry of Economic Affairs decided to interrupt shale gas exploration and commission a group of industry experts in order to investigate the environmental risks and impacts associated with shale gas development in the Netherlands.

In August 2013, Dutch Minister of Economic Affairs Henk Kamp released the results of the investigation in a letter to the Parliament and declared that “risks from fracking to produce shale gas can be overcome.” Furthermore, the Minister specified that “possible consequences and risks to nature, humans and the environment are manageable and can be addressed within existing legal frameworks.”

Following the release of this report, the Dutch Ministry of Economic Affairs asked for additional advice from the Netherlands Commission for Environmental Assessment (NCEA) for the purpose of evaluating the objectivity and quality of the report findings. In September 2013, the NCEA suggested the need to prepare an Environmental Impact Assessment (EIA) for each shale gas project, but pointed out that “it is not possible to declare shale gas exploration ‘safe’ and merely continue permitting specific projects.” Consequently, the NCEA strongly advised the Dutch government to develop a Structure Vision for shale gas exploration, which included the preparation of an EIA plan in order to assess whether shale gas development in the Netherlands would be environmentally sound and economically beneficial, to which the government agreed.

On September 18, 2013, the Dutch Ministry of Economic Affairs informed the Dutch Parliament that a Structure Vision would be developed in cooperation with the Dutch Ministry of Infrastructure and the Environment. As a first step, the Dutch government declared that it would conduct the EIA plan detailing the impacts of shale gas extraction and production in the Netherlands on the environment. The results of the EIA plan were to be identified later in the Structure Vision.

On September 9, 2014, the NCEA issued its Recommendations on the scope and detail of the environmental impact assessment relating to the Structure Vision and urged the government to provide “insight into the balance between the economic and environmental aspects at regional, national and where relevant international level,” among other things.  In October 2014, the Dutch Minister of Economic Affairs released the definitive Memorandum on the Scope and Detail for the Environmental Impact Assessment (EIA) for shale gas.

The Dutch government indicated that the EIA plan and draft of the Structure Vision was to be released within the year of 2015. Shortly thereafter, however, in a News Release dated July 10, 2015, the Dutch Ministry of Economic Affairs declared that “no commercial exploration or extraction of shale gas will take place in the Netherlands over the next five years.”

Interestingly, the Dutch Ministry of Economic Affairs expressed in the 2015 Energy Report that the government “do[es] not yet know whether the commercial exploitation of shale gas will be needed in the longer term” before highlighting that such need “will depend, among others, on the pace and the direction of the transition, and the use of natural gas will in any case be reduced as much as possible by means of implementing energy conservation measures and replacing it with renewable sources.” In addition, the Dutch Ministry of Economic Affairs pointed out that “many years of research will be required to facilitate a judicious decision-making process for licensing the commercial exploitation of shale gas, particularly in light of the potential risks and the social unrest caused by the shale gas debate.”

The years of study, carried out as part of the Structure Vision development, together with the implementation of the five-year moratorium, demonstrate that the Netherlands has the potential for shale gas development. In the short term, however, development will not occur while prospects for development over the long term also remain uncertain.

Wednesday, February 7, 2018

Shale Law in the Spotlight: Oil and Natural Gas Severance Taxes in the United States (Florida, New York, Tennessee, Illinois, and Virginia)


Written by Chloe Marie – Research Fellow

This series addresses severance taxes on oil and natural gas imposed by various states, and this seventh and last article will review the severance tax systems for the state of Florida, New York, Tennessee, Illinois, and Virginia. In six prior articles, we addressed the severance tax systems for the states of Pennsylvania, Ohio, and West Virginia; for the states of Texas, Oklahoma, Louisiana, and Wyoming; for the states of North Dakota, Arkansas, New Mexico, and Colorado, for the states of Kansas, South Dakota, Montana, Utah; for the states of Indiana, Kentucky, Alabama, and Mississippi; and for the states of Michigan, Alaska, Nebraska, and California.

Florida

In Florida, there is a production tax imposed on oil and natural gas severed in the state (Fl. Code Chapter 211). Oil is taxed at a rate of 8% of the gross value at the point of production. Oil produced from wells capable of producing less than 100 barrels per day is taxed at a reduced rate of 5% at the point of production. For oil that has escaped from wells, the tax rate is set up at 12.5%. In addition, oil produced using tertiary methods is taxed based on the value or market price of a barrel of oil at the wellhead using tiered formulas, as follows: 1% is levied on the first $60 of gross value; 7% is levied on the gross value greater than $60 and less than $80; 9% is levied on the gross value greater than $80.

Natural gas is taxed at a rate determined annually by the Florida Department of Revenue and is based on the volume of gas produced and sold or used by a producer during the month. The tax rate is calculated based on the previous calendar year’s producer price indices published by the U.S. Bureau of Labor Statistics and, as of July 1, 2017, the natural gas production tax rate is $0.172 per Mcf.

Tax exemptions also are provided for oil or gas production used for lease operations on the lease or unit where produced; gas reinjected into the producing field; unsold gas vented or flared directly into the atmosphere; oil and gas produced from new field wells, completed after July 1, 1997, for a period of 60 months after the completion date; oil and gas produced from new wells in existing fields as well as from shut-in wells or temporarily abandoned wells or wellbores, completed after July 1, 1997, for a period of 48 months after the completion date; and oil and gas produced after July 1, 1997, for a period of 60 months after the completion date from any horizontal well or any well having a total measured depth in excess of 15,000 feet.

The revenue received from the severance tax is collected by the Florida Department of Revenue and deposited in the Oil and Gas Tax Trust Fund. From the balance of this fund, a “sufficient amount” must be appropriated to the Chief Financial Officer for refund purposes while the remainder must be distributed to the General Revenue Fund of the board of county commissioners of producing counties and to the Minerals Trust Fund.

New York

In New York, there is no statewide severance tax on oil and gas production; however, the New York Real Property Tax law provides for an annual assessment of oil and gas rights in New York oil and gas producing properties based on the appropriate unit of production value and determined by the New York Office of Real Property Tax Services (ORPTS). Oil and gas producing properties include oil and gas wells, pipelines, reserves, etc.

According to the ORPTS’ Overview Manual, the unit of production value for oil is stated as a dollar amount per daily average of oil production or per barrel of oil produced while the unit of production value for natural gas is expressed in dollars per 1,000 cubic feet (Mcf) produced or dollar per daily average. In March 2017, the ORPTS issued a certificate providing for the Final 2017 Oil and Gas Unit of Production Values.

Tennessee

The Tennessee Code imposes a severance tax on producers removing oil and gas from the ground in Tennessee at a rate of 3% of the oil and gas sale price (T.C.A. § 60-1-301). In addition, the Tennessee Code provides that the revenue received from the severance tax is exclusively for the use and benefit of the state and local governments and must be distributed as follows: 1/3 of the revenue collected must be allocated to the county where the wellhead is located while the remaining 2/3 of the revenue must be allocated to the state general fund.

Illinois

The Illinois Hydraulic Fracturing Tax Act (35 ILCS 450/2-15) levies a statewide severance tax on oil and natural gas produced on or after July 1, 2013, based on different rate formulas. During the first 24 months of initial production, the Illinois legislature provides for a 3% reduced tax rate of the value of the oil and gas severed within the state. The tax rate thereafter is determined as follows:
-          A tax rate of 3% applies to the value of oil where the average daily production from the well is less than 25 barrels on a monthly basis;
-          A tax rate of 4% applies to the value of oil where the average daily production from the well is 25 or more barrels but less than 50 barrels on a monthly basis;
-          A rate 5% applies to the value of oil where the average daily production from the well is 50 or more barrels but less than 100 barrels on a monthly basis;
-          For natural gas, a 6% tax rate applies to the value of natural gas.

The Illinois Hydraulic Fracturing Tax Act also provides for a tax exemption where the oil is produced from a well with average daily production of 15 barrels or less for the first 12 months of initial production. Tax exemptions also apply to gas injected into the ground for the purpose of lifting oil, recycling, or repressuring; gas used for fuel in connection with the operation and development for, or production of, oil or gas in the production unit where severed; gas lawfully vented or flared; and gas inadvertently lost on the production unit by reason of leaks, blowouts, or other accidental losses.

Virginia

The Virginia Code § 58.1-3712 authorizes counties and cities to levy a severance tax at a rate that should not exceed 1% of the gross receipts from the sales of natural gas severed within the county or city. The counties concerned are Tazewell, Dickenson, Buchanan, and Wise counties as well as the City of Norton, and all impose a 1% tax rate of the gross receipts from the sale of natural gas severed.
The money received from the severance tax for each county and city must be paid into a special fund of such county or city called the Coal and Gas Road Improvement Fund, and this money must be used for the purpose of improving public roads (§ 58.1-3713).

Tuesday, February 6, 2018

Shale Law Weekly Review - February 6, 2018

Written by:
Jacqueline Schweichler - Education Programs Coordinator

The following information is an update of recent local, state, national, and international legal developments relevant to shale gas.

State Regulation: Pennsylvania DEP Announces New Funding for Additional Staff
On January 26, 2018, Governor Wolf and the Pennsylvania Department of Environmental Protection (DEP) announced a plan to allocate $2.5 million in the 2018-19 fiscal year for additional staffing. In the press release, DEP stated that over the past ten years DEP staff was reduced by 43% which has caused a significant backlog and an increased wait time for permits. The purpose of the plan is to “reduce permit backlogs, modernize permitting processes, and better utilize technology to improve both oversight and efficiency.” Some of the new initiatives include expanding the e-permitting system, creating a new analytics program, releasing new review processes for permits, and supporting legislation for extended permit terms.

Production and Operation: Pennsylvania DEP Launches Initiative to Plug Abandoned Oil and Gas Wells
On January 30, 2018, the Pennsylvania Department of Environmental Protection (DEP) announced a new initiative that encourages private-sector groups to participate in the program to cap abandoned oil and gas wells within the state. DEP is offering liability protection for private parties assisting in the program. According to DEP, there are thousands of abandoned wells in Pennsylvania that constitute health, safety, and environmental hazards. The program is being offered under the Environmental Good Samaritan Act of 1999 which “protects groups and individuals who volunteer to implement qualifying environmental remediation projects from civil and environmental liability.” The program does not provide immunity for damage caused by reckless or grossly negligent acts or omissions.

Crude Oil by Rail: Washington Governor Denies Oil-by-Rail Terminal in Vancouver
On January 29, 2018, Washington Governor, Jay Inslee, announced the decision to reject a permit for the new oil-by-rail terminal at the Port of Vancouver. The 360,000 barrel-per-day terminal was proposed by the Tesoro-Savage Joint Venture. The Energy Facility Site Evaluation Council (Council) evaluated the project and recommended in November 2017 that the permit be denied. The governor’s decision to deny the permit was based on several issues including “seismic risks, the inability to sufficiently mitigate oil spill risks, and the potential safety risks of a fire or explosion.” Tesoro Savage will have 30 days to appeal the permit denial.

PA Impact Fee: Pennsylvania Independent Fiscal Office Releases Impact Fee Estimate
On January 31, 2018, Pennsylvania Independent Fiscal Office (IFO) released their 2017 Impact Fee Estimate. The impact fee in Pennsylvania is imposed on unconventional wells and the proceeds are distributed to local governments and state agencies. The proceeds are used for infrastructure, emergency services, and environmental initiatives. IFO estimates an impact fee collection of $219.4 million for 2017, which constitutes a $46 million increase from 2016.

LNG Exports: Maryland Cove Point LNG Facility Begins Production
On January 31, 2018, Dominion Energy’s Cove Point LNG Export Project began producing liquefied natural gas at its Maryland facility. Construction of the facility began in October 2014 and final export approval was granted by the Federal Energy Regulatory Commission in November 2017. Cove Point is located on the Chesapeake bay in Lusby, Maryland. The project cost $4 billion and will process approximately 750 million cubic feet per day of inlet feed gas. The natural gas for the facility will be sourced from the Marcellus and Utica Shale Plays.

National Energy Policy: BLM Releases Memorandum on Oil and Gas Leasing Policy
On January 31, 2018, the U.S. Bureau of Land Management (BLM) released an Instruction Memorandum setting out a new policy to streamline the oil and natural gas drilling process  on federal lands. The policy encourages the simplifying and streamlining of land use planning, lease parcel review, lease sales and lease issuance. Under the new policy, BLM will no longer use a rotating lease sale schedule. The new policy also rescinds the use of Master Leasing Plans and sets a time frame for parcel review of lease sales to be no longer than 6 months. These changes and the memorandum, Updating Oil and Gas Leasing Reform - Land Use Planning and Lease Parcel Reviews can be found on the BLM’s website.

Induced Seismicity: Study Suggests Increase in Seismicity in Oklahoma Due to Wastewater Injection
On February 1, 2018, research published in Science, found that the increase in seismicity in Oklahoma is likely due to wastewater injection. The study found that “injection depth relative to crystalline basement most strongly correlates with seismic moment release.” The depth of the wastewater injection combined with the volume of liquid created the greatest seismic effect. The researchers recommend limiting the depth of wastewater injection to reduce the effects of induced seismicity in Oklahoma. The study is entitled, Oklahoma’s Induced Seismicity Strongly Linked to Wastewater Injection Depth.

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Friday, February 2, 2018

Global Shale Law Compendium: Shale Governance in Mid-Atlantic states (Virginia, New Jersey, Delaware, Pennsylvania, New York, and Maryland)


Written by Chloe Marie – Research Fellow


The Global Shale Law Compendium series addresses legal developments and other issues related to the governance of shale oil and gas activities in various countries and regions of the world. In this article, we will focus on legal, policy, and governance issues related to shale gas development in the United States, and more specifically in the Mid-Atlantic states.

Virginia

The state of Virginia is not viewed as a significant natural gas-producing state within the United States. Indeed, according to the U.S. EIA, Virginia holds less than 1% of the United States’ total natural gas reserves and said reserves are limited to the southwestern portion of Virginia.

The Virginia Division of Gas and Oil has stated that the only producing oil and gas wells in Virginia are situated in the southwestern portion of Virginia before adding that exploratory well drilling also occurred in other portions of the state. Those exploratory wells, however, were plugged due to insufficient quantities of hydrocarbons for commercial production. Interestingly, the Division of Gas and Oil stated that “the advent of horizontal drilling along with existing hydraulic fracturing technology renewed interest in some of these areas, including areas underlain by the Marcellus Shale in the western mountains and valleys, and the Mesozoic basins of eastern Virginia.” According to the USGS, potential resources may be found in Highland, Rockingham, and Shenandoah Counties, VA.

As of 2014, the Division of Gas and Oil explained that the technique of hydraulic fracturing had been used since the 1950s in approximately 2,100 wells producing from shale, sandstone and limestone formations in Southwest Virginia.

Other information also identified the Upper Devonian and Huron Shale plays as having potential for shale gas resources in Virginia. The Upper Devonian is located in Western New York, Western and Northeast Pennsylvania, Western West Virginia, Eastern Ohio and Eastern Kentucky, but also with a little overlap in Southwest Virginia. As a result, the Virginia Division of Geology and Mineral Resources launched what is called the Resource Assessment and Exploration Potential of the Devonian Gas Play in Virginia project. This project’s purpose is to “develop a geologic model of the Devonian shale gas play in Virginia;” “assess the hydrocarbon resource in area where it is currently productive;” and “evaluate the exploration potential for this gas play in Virginia.” The Division of Geology and Mineral Resources, however, did not provide any information as to the commencement and end dates for the project.

New Jersey

According to the U.S. EIA, natural gas development has never occurred in New Jersey, though “New Jersey has geologic indications of natural gas deposits in its northern half but no proved natural gas reserves.” Despite the lack of historic development, the New Jersey legislature has attempted several times to enact legislation that would ban the use of hydraulic fracturing or related activities in the state.

On June 29, 2011, the New Jersey legislature passed SB 2576 to permanently prohibit the use of the hydraulic fracturing technique for natural gas development in the state. This legislation stated that such technique would create an unacceptable risk to the people of New Jersey specifically identifying an incident that occurred in June 2010 at a natural gas drilling site in Clearfield County, Pennsylvania. Governor Chris Christie then conditionally vetoed this bill on August 25, 2011, declaring that a one-year ban would be more appropriate to the situation “so that the DEP can further evaluate the potential environmental impacts of this practice in New Jersey as well as evaluate the findings of still outstanding and ongoing federal studies.”

Later, respectively on June 21 and 25, 2012, the New Jersey Assembly and Senate passed Assembly Bill 575 to prohibit the treatment, discharge, disposal, or storage of any wastewater resulting from hydraulic fracturing for the purpose of natural gas development. Again, Governor Chris Christie vetoed the bill pointing out that this legislation was unnecessary as the use of hydraulic fracturing was not occurring in the state and was unlikely to occur in the future. 

Delaware

The U.S. EIA has stated that Delaware does not possess any oil or natural gas reserves as of July 2017. The Agency also added that “exploratory drilling in the 1970s and 1980s off the state’s Atlantic Coast found no commercial natural gas or crude oil resources but did discover one noncommercial natural gas deposit.”

Pennsylvania

The Marcellus Shale formation represents one of the largest shale gas plays in the U.S. and underlies over “three-fifths” of Pennsylvania based on the U.S. EIA Pennsylvania’s profile analysis. The state of Pennsylvania is one of the most prolific shale gas producers in the country with 1,321 unconventional well drilling permits issued in 2016 and 5.1 trillion cubic feet of natural gas produced from unconventional wells according to the Pennsylvania DEP’s 2016 Oil and Gas Annual Report. Washington, Greene and Susquehanna Counties recorded the greatest number of unconventional gas wells in 2016.

We have discussed legislative developments related to shale development in Pennsylvania in three prior articles: the first addressing legislation during the time periods from 2010 to 2012; the second addressing legislation during the time period from 2013 to 2016; and the third addressing legislation enacted through the annual fiscal code legislation from 2009 to 2017.  Additional articles are planned to address regulatory developments applicable to shale gas development in Pennsylvania.

New York

Although the first commercial natural gas well was drilled near Fredonia, New York in 1825, the U.S. EIA has stated that “there has been no development of natural gas shale resources in New York, and the total amount of retrievable natural gas under the state is unclear.” The use of hydraulic fracturing for shale gas development has long been a topic of controversy in the state of New York. Governmental concerns about the potential environmental and public health impacts of such technique caused the state to permanently ban high volume hydraulic fracturing, which is essential to shale gas development, in June 2015 after years of public discussion.

In a prior article, we discussed the timeline of regulatory actions leading to the permanent ban of shale gas development in New York.

Maryland

As of October 1, 2017, shale gas development using hydraulic fracturing has been permanently prohibited in the state of Maryland. Prior to the enactment of this ban, no shale development had occurred in Maryland despite some level of interest by the industry in the Marcellus Shale region underlying western Maryland. The U.S. EIA states that Maryland’s natural gas production is very low before adding that “most of the natural gas wells in the state are storage wells, but the few low-producing wells in far western Maryland produce less than 50 million cubic feet of natural gas annually.”

In a previous article, we addressed the timeline of legal actions leading to the permanent ban of shale gas development in the state of Maryland.