Wednesday, February 21, 2018

Shale Law in the Spotlight: Overview of the Greater Sage-Grouse Resource Management Plan Reform


Written by Chloe Marie – Research Fellow

The U.S. Fish & Wildlife Service (FWS) describes the Greater sage-grouse as a large, rounded-winged, ground-dwelling bird unique to North America. Historically, there have been concerns about the extent to which the sagebrush habitat of the Greater sage-grouse has been affected by oil and gas development and its associated infrastructure. In September 2015, however, FWS found that “the threats which caused the Service to initially designate the bird ‘warranted but precluded’ in 2010 had been significantly reduced due to federal and state land use conservation plans.” Therefore, the U.S. Department of Interior (DOI) announced in a Press Release that the Greater sage-grouse should no longer be protected under the Endangered Species Act, but DOI insisted on the need to continue to focus efforts on the Greater sage-grouse conservation measures when developing federal and state land management plans.

In this regard, the U.S. Bureau of Land Management (BLM) issued an Instruction Memorandum 2016-143 in December 2016 providing guidance on the implementation of the Greater sage-grouse Resource Management Plan. Instruction Manual 2016-143 draws particular attention to the objective of prioritizing oil and gas leasing and development outside of the Greater sage-grouse habitat management areas.

On December 27, 2017, the BLM released a new Instruction Manual 2018-026 replacing and superseding the prior Instruction Manual 2016-143 developed during the Obama administration. While stating that the new Instruction Manual continues to prioritize leasing outside of the Greater sage-grouse habitat, BLM also declared that applications for a lease outside of the Greater sage-grouse habitat management areas do not need to be considered before those within it. The new Instruction Manual points out that “this policy should allow for BLM to efficiently conduct lease sales and permit oil and gas development while still protecting [the Greater sage-grouse] and [the Greater sage-grouse habitat].”

More precisely, the new Instruction Manual emphasizes that certain leasing stipulations, such as No Surface Occupancy (NSO) and Controlled Surface Use (CSU), can be used as a way to promote leasing outside of Greater sage-grouse higher priority habitat management areas. In addition, BLM also prioritizes leasing applications based on “office workload capacity, first-in/first-out, priority for unit obligation wells, processing the easiest applications first, operator drilling plans, operator proposals for units, potential drainage cases, and other resource values that must be considered.”

Monday, February 19, 2018

Shale Law Weekly Review - February 19, 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.

Methane Emissions: BLM Proposes Revisions to Waste Prevention Rule
On February 12, 2018, the U.S. Bureau of Land Management (BLM) announced a proposed rule revising the Waste Prevention, Production Subject to Royalties, and Resource Conservation rule, known as the “venting and flaring rule.” The rule is part of a regulatory review spurred by the 2017 executive order, Promoting Energy Independence and Economic Growth. The purpose of the revision is to “eliminate duplicative regulatory requirements” and encourage domestic energy production. Public comments on the proposed rule are due within 60 days of the rule’s publication in the Federal Register.

Wastewater Treatment/Disposal: Environmental Groups Sue EPA for Alleged Oil and Gas Pollution in the Gulf
On February 13, 2018, several environmental groups filed a lawsuit against the U.S. Environmental Protection Agency (EPA) for granting permits allowing oil and gas companies to dispose of leftover waste from drilling and hydraulic fracturing operations in the Gulf of Mexico. The lawsuit, filed in the U.S. Court of Appeals for the 5th Circuit, states that EPA violated the Clean Water Act and the National Environmental Policy Act. Specifically, the environmental groups challenge that Clean Water Act permit issued for new and existing offshore oil and gas platforms near Texas and Louisiana. According to the Center for Biological Diversity (CBD), the permit allows oil and gas companies to dump unlimited waste fluid into the Gulf of Mexico. CBD states that the largest concentration of offshore oil and gas drilling activity occurs within this area and tens of billions of gallons of wastewater are deposited yearly.

State Regulation: Colorado Approves New Rules for Flowlines
On February 13, 2018, the Colorado Oil & Gas Conservation Commission(COGCC) approved new rules for detecting and preventing spills from flowlines. COGCC began the rulemaking process last year after a broken flowline caused a home explosion in Firestone. The new rules set new installation, testing, and shut-down requirements for flowlines, according to the Associated Press. The new rules can be found here.

Induced Seismicity: Research Suggests Different Seismicity Effects Result from Hydraulic Fracturing Depths
On February 5, 2018, the Proceedings of the National Academy of Sciences of the United States of America (PNAS) published an article that focuses on induced seismicity as a result of hydraulic fracturing. The researchers focused on Harrison County, Ohio where no seismicity was found before 2010 and the arrival of wastewater injection and hydraulic fracturing into the area.  The study found induced seismicity in two depth zones, including a shallower zone in Paleozoic rocks and a deeper zone on old faults in the Precambrian basement. The research suggests that induced seismicity at the shallower depth zone created more small-magnitude earthquakes that continued after drilling ceased. They also found that the deeper zones resulted in larger magnitude earthquakes where the seismicity stopped in conjunction with drilling.

Production and Operation: EIA 2016 Year-End Report Shows Increase In Pennsylvania Natural Gas Reserves
On February 13, 2018, the U.S. Energy Information Administration (EIA) released their Year-end 2016 U.S. Crude Oil and Natural Gas Proved Reserves. Total natural gas proved reserves in the United States in 2016 increased from 324.3 trillion cubic feet (Tcf) to 341.1 Tcf. In 2016, Pennsylvania had the greatest shale natural gas proved reserves. In addition, Pennsylvania experienced the highest net increase of natural gas proved reserves with a 6.1 Tcf increase. EIA attributes the significant increase in Pennsylvania’s natural gas reserves to the development of the Marcellus shale.

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

Stay informed with our monthly Agricultural Law Brief located here.


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 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.

Follow us on Twitter at PSU Ag & Shale Law (@AgShaleLaw) to receive ShaleLaw HotLinks

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


Stay informed with our monthly Agricultural Law Brief located here.

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).