According to the North Dakota Industrial Commission, the amount of crude oil produced in the state has decreased dramatically. Whereas 1.2 MMb/d of crude oil was produced in the state in December, only 37 Mb/d was produced in January. In addition, the number of wells completed in the state also dropped. Commentators have speculated that the drop in production and well completions is the result of low crude oil prices. However, companies may simply be biding their time until North Dakota tax incentives are triggered.
Two taxes apply to the majority of the crude oil produced in North Dakota. The gross value of crude oil produced in the state is subject to a 5% gross production tax (GPT) and a 6.5% extraction tax. Crude oil produced on American Indian land is exempt from the GPT. During times of low crude oil prices, North Dakota has waived or, at a minimum, lowered the extraction tax applicable to crude oil.
One tax incentive employed by North Dakota is the Small Trigger. The Small Trigger became effective in February 2015. The North Dakota Legislature created the tax incentive to encourage the drilling of new wells and increase crude oil production. The tax break is available whenever the monthly average price for West Texas Intermediate (WTI) crude oil is below $57.50/Bbl. Rather than imposing a 6.5% tax, the extraction tax lowers to 2% for the first $4.5 million or 75 MBbl produced, whichever is first. This tax break continues up until the first eighteen months once a well is completed and only covers wells finished after February 1, 2015. The tax incentive is only available until June 30, 2015. If the average WTI price rises above $72.50/Bbl, however, the tax break would no longer be available.
If crude oil prices remain lower than $55/Bbl, another tax incentive referred to as the Large Trigger would go into effect. Under the Large Trigger, if the price of oil drops below $55.09/Bbl, the 6.5% tax on extraction will be waived. The tax incentive is not triggered until the monthly average WTI price falls below the threshold for at least 5 consecutive months. If triggered, the tax incentive would be available until the average monthly oil price rises above the threshold for five consecutive months. For the first 24 months after the incentive is triggered, the incentive permits oil producers to avoid paying the entire 6.5% extraction tax on old and new producing wells. After the initial 24 month period, the Large Trigger reduces the extraction tax to 4%.
For more information on drilling economics, click here.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
Showing posts with label North Dakota. Show all posts
Showing posts with label North Dakota. Show all posts
Opposition to federal fracking rules grows
Earlier this year, the Department of Interior’s Bureau of Land Management (BLM) released its final version of rules governing hydraulic fracturing on federal land. As discussed in a previous post, these rules will not only impose heightened requirements on drilling operations but also increase the reporting duties for drilling operators. Shortly after the BLM released its proposal, the Independent Petroleum Association of America (IPAA) and Western Energy Alliance (WEA) sued the BLM in Wyoming to challenge the proposed rules. The IPAA and WEA argued that the BLM’s rules are unnecessary because states adequately regulate hydraulic fracturing. The IPAA and WEA have also alleged that the BLM’s final rules are unsubstantiated.
A second lawsuit was later filed by Wyoming against the BLM. In its petition for review of the BLM’s fracking rules, Wyoming stated that the BLM exceeded its authority and its fracking rules would hamper state regulation of hydraulic fracturing. Specifically, Wyoming has argued that the BLM’s authority under the Mineral Leasing Act and the Federal and Policy and Management Act do not authorize the agency to enact the hydraulic fracturing rules. According to Wyoming, the BLM’s rules also conflict with the Safe Water Drinking Act, which grants states the exclusive right to regulate underground injections. North Dakota later joined Wyoming’s petition for review. North Dakota has stated that it is one of the largest oil and gas producers in the United States and the BLM’s rules inhibit the state’s ability to regulate hydraulic fracturing in the state.
The opposition to the United States Bureau of Land Management’s (BLM) rules for hydraulic fracturing is growing. Colorado has also joined the lawsuit challenging the BLM’s new rules for hydraulic fracturing. Cynthia Coffman, the Attorney General for Colorado, describes the BLM’s rules as an encroachment on an area that has historically been regulated by states. Coffman further noted that Colorado has sufficient regulations governing hydraulic fracturing. In addition, Coffman stated that although hydraulic fracturing should be regulated, the BLM lacked the authority to enact the rules.
Read the amended petition for review.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
A second lawsuit was later filed by Wyoming against the BLM. In its petition for review of the BLM’s fracking rules, Wyoming stated that the BLM exceeded its authority and its fracking rules would hamper state regulation of hydraulic fracturing. Specifically, Wyoming has argued that the BLM’s authority under the Mineral Leasing Act and the Federal and Policy and Management Act do not authorize the agency to enact the hydraulic fracturing rules. According to Wyoming, the BLM’s rules also conflict with the Safe Water Drinking Act, which grants states the exclusive right to regulate underground injections. North Dakota later joined Wyoming’s petition for review. North Dakota has stated that it is one of the largest oil and gas producers in the United States and the BLM’s rules inhibit the state’s ability to regulate hydraulic fracturing in the state.
The opposition to the United States Bureau of Land Management’s (BLM) rules for hydraulic fracturing is growing. Colorado has also joined the lawsuit challenging the BLM’s new rules for hydraulic fracturing. Cynthia Coffman, the Attorney General for Colorado, describes the BLM’s rules as an encroachment on an area that has historically been regulated by states. Coffman further noted that Colorado has sufficient regulations governing hydraulic fracturing. In addition, Coffman stated that although hydraulic fracturing should be regulated, the BLM lacked the authority to enact the rules.
Read the amended petition for review.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
North Dakota considers additional regulation of oil and gas operations
Several federal agencies have announced that they will adopt additional regulations for the oil and gas industry this year. It appears that states are also weighing additional regulatory measures. North Dakota is contemplating legislation targeted at reducing the time oil companies burn natural gas from oil wells.
The bill proposal is sponsored by Senator Connie Triplett. If enacted, the bill would mandate that companies pay royalties and taxes on natural gas within fourteen days after an oil well starts production. Under the current system, companies need not pay royalties or taxes until a year after the beginning of production. If a company is found in violation of this bill, the bill authorizes the industrial commission to determine the amount of royalties to be paid by the company.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
The bill proposal is sponsored by Senator Connie Triplett. If enacted, the bill would mandate that companies pay royalties and taxes on natural gas within fourteen days after an oil well starts production. Under the current system, companies need not pay royalties or taxes until a year after the beginning of production. If a company is found in violation of this bill, the bill authorizes the industrial commission to determine the amount of royalties to be paid by the company.
One of the motivations for this bill proposal, according to Triplett, is that the current regulatory system deprives mineral owners and North Dakota of revenue they should receive from the wasted gas. Over the past couple of years, flared natural gas has constituted approximately one-third of oil production in North Dakota. The percentage has decreased recently, however, due in large part to a policy circulated by state regulators last year.
In July 2014, state regulators issued a policy encouraging oil and gas operators to reduce the amount of natural gas flared by 2020. If companies are unable to meet the flaring limits set by state regulators, the regulators have the authority to establish production limits.
Read the proposed bill.
In July 2014, state regulators issued a policy encouraging oil and gas operators to reduce the amount of natural gas flared by 2020. If companies are unable to meet the flaring limits set by state regulators, the regulators have the authority to establish production limits.
Read the proposed bill.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
North Dakota adopts heightened safety standards for the transportation of oil by rail
The increase in the number of accidents involving the transportation of oil by rail has increased the scrutiny on shippers of Bakken crude oil. In response, the United States Department of Transportation has proposed new rules to govern the shipment of oil by rail and has also issued emergency orders on this topic. It appears that states are beginning to take an active role in the regulation of Bakken crude oil as well.
On December 9th, the North Dakota Industrial Commission (Commission) announced new regulations governing the shipment of Bakken crude oil in the state. Under the new standards, companies must separate light hydrocarbons from Bakken crude oil produced in the state and take measures to ensure that the hydrocarbons are not mixed into the oil before it is shipped. The new standards will take effect on April 1, 2015.
With the adoption of these new rules, North Dakota’s requirements for the shipment of Bakken crude oil are stricter than national standards. Whereas North Dakota now requires Bakken crude oil to have a vapor pressure of 13.7 pounds per square inch (psi) or lower, the national standards only require a psi of 14.7 or lower. To ensure compliance, North Dakota’s Department of Mineral Resources will conduct field inspections, and parties found violating the order could receive fines as high as $12,500 for each day they violate the new rules. The Commission has stated, however, that companies may request a hearing with the Commission if they wish to utilize an alternative stabilization process.
Read the order.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
On December 9th, the North Dakota Industrial Commission (Commission) announced new regulations governing the shipment of Bakken crude oil in the state. Under the new standards, companies must separate light hydrocarbons from Bakken crude oil produced in the state and take measures to ensure that the hydrocarbons are not mixed into the oil before it is shipped. The new standards will take effect on April 1, 2015.
With the adoption of these new rules, North Dakota’s requirements for the shipment of Bakken crude oil are stricter than national standards. Whereas North Dakota now requires Bakken crude oil to have a vapor pressure of 13.7 pounds per square inch (psi) or lower, the national standards only require a psi of 14.7 or lower. To ensure compliance, North Dakota’s Department of Mineral Resources will conduct field inspections, and parties found violating the order could receive fines as high as $12,500 for each day they violate the new rules. The Commission has stated, however, that companies may request a hearing with the Commission if they wish to utilize an alternative stabilization process.
Read the order.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
Increased rail traffic leads to heightened regulations
Compared to last year, transportation of goods by rail has increased. The two commodities with the largest increase in rail traffic have been coal and crude oil products. Transportation of crude oil and petroleum products by rail has increased by 13.4 percent. From January to October 2014, more than 672,000 tank cars have transported oil and petroleum products. Commentators have suggested that the increase is a result of the increased production of crude oil and the limited amount of pipeline available to transport the material. The amount of crude oil and petroleum products transported by rail pales in comparison to the amount of coal transported. Approximately 4.9 million tank cars of coal were shipped from January to October 2014.
The increased rail traffic has led federal and state regulators to impose additional requirements on rail carriers. The United States Department of Transportation’s Surface Transportation Board (STB) recently imposed a requirement that rail carriers submit weekly reports on their delivery performance. These reports will permit the STB to track the shipments and identify any potential problems from the increased rail traffic.
In addition, Lynn Helms, the Mineral Resources Director for North Dakota, has proposed new regulations for rail carriers in the state. Under the new rules, companies must lower the volatility of crude oil before it can be transported by rail. Specifically, the proposed rules would require crude oil to have a vapor pressure lower than 13.7 pounds per square inch (psi). National standards only require crude oil to have a vapor pressure lower than 14.7 psi. The proposal has been submitted to the North Dakota Industrial Commission (Commission). The Commission will meet on December 11th to discuss whether to adopt the proposal.
Although several members of the Commission have expressed their support for the proposed rules, members of the oil and gas industry have stated their displeasure with the proposal. According to opponents of the regulation, the proposal unduly focuses on crude oil and fails to address the true problem—safe rail transportation. Opponents also argue that the treatment process envisioned by the proposal would increase the amount of volatile material needed to be transported. Lastly, opponents argue that the treatment process would cause increased emissions from the amount of heating required to remove the chemicals from the gas.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
The increased rail traffic has led federal and state regulators to impose additional requirements on rail carriers. The United States Department of Transportation’s Surface Transportation Board (STB) recently imposed a requirement that rail carriers submit weekly reports on their delivery performance. These reports will permit the STB to track the shipments and identify any potential problems from the increased rail traffic.
In addition, Lynn Helms, the Mineral Resources Director for North Dakota, has proposed new regulations for rail carriers in the state. Under the new rules, companies must lower the volatility of crude oil before it can be transported by rail. Specifically, the proposed rules would require crude oil to have a vapor pressure lower than 13.7 pounds per square inch (psi). National standards only require crude oil to have a vapor pressure lower than 14.7 psi. The proposal has been submitted to the North Dakota Industrial Commission (Commission). The Commission will meet on December 11th to discuss whether to adopt the proposal.
Although several members of the Commission have expressed their support for the proposed rules, members of the oil and gas industry have stated their displeasure with the proposal. According to opponents of the regulation, the proposal unduly focuses on crude oil and fails to address the true problem—safe rail transportation. Opponents also argue that the treatment process envisioned by the proposal would increase the amount of volatile material needed to be transported. Lastly, opponents argue that the treatment process would cause increased emissions from the amount of heating required to remove the chemicals from the gas.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
IPAA response to proposed rule on transportation of crude oil by rail
The Independent Petroleum Association of America (IPAA) and the North Dakota Petroleum Council (NDPC) recently submitted comments regarding the proposed rule concerning the shipping of crude oil by rail. In the rule, the Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) specified, among other things, that the tanker car fleet currently used must be retrofitted within a two-year period to comply with heightened standards specified in the rule.
The IPAA and NDPC commented that, according to industry experts, at least six years are needed to replace the current fleet. Imposing a two-year phase-out would, in the IPAA and NDPC’s view, hinder oil producers from timely providing the market with crude oil. Additionally, the IPAA and NDPC argued that the PHMSA unnecessarily targeted Bakken crude oil because it does not impose a heightened safety risk. For support, the IPAA and NDPC relied on several reports that Bakken oil is not more dangerous that crude oil in other areas of the United States.
Read additional concerns raised by the IPAA and NDPC.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
The IPAA and NDPC commented that, according to industry experts, at least six years are needed to replace the current fleet. Imposing a two-year phase-out would, in the IPAA and NDPC’s view, hinder oil producers from timely providing the market with crude oil. Additionally, the IPAA and NDPC argued that the PHMSA unnecessarily targeted Bakken crude oil because it does not impose a heightened safety risk. For support, the IPAA and NDPC relied on several reports that Bakken oil is not more dangerous that crude oil in other areas of the United States.
Read additional concerns raised by the IPAA and NDPC.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713 651 3662) and Johnjerica Hodge (johnjerica.hodge@nortonrosefulbright.com or 713 651 5698) from Norton Rose Fulbright's Energy Practice Group.
Reports show Bakken crude oil within safety standards
The North Dakota Petroleum Council (NDPC) and the American Fuel & Petrochemical Manufacturers (AFPM) recently released the results of studies relating to the characteristics of Bakken crude oil and the standards required to transport crude oil by rail.
These studies in part respond to a safety alert issued on January 2, 2014, by the Pipeline and Hazardous Materials Safety Administration (PHMSA), which notified “the general public, emergency responders, and shippers and carriers that recent derailments and resulting fires indicate that the type of crude oil being transported from the Bakken region may be more flammable than traditional heavy crude oil.”
The May 14, 2014 report prepared for AFPM presents testing data that demonstrates that “Bakken crude is well within the safety standards for current rail car designs.” The data also shows that “Bakken crude is comparable to other light crudes and does not pose risks that are significantly different than other crudes of flammable liquids authorized for rail transport.”
Because Bakken crude is within the regulatory limits for pressure, flashpoint, boiling point and corrosivity for use in Department of Transportation (DOT) approved railcars, AFPM concludes that Bakken crude is a Class 3 Flammable Liquid and there is no need to create a new DOT classification for crude oil transportation.
At a conference on May 20, 2014, the NDPC released a study in which Bakken crude was found to be a typical Class 3 flammable liquid, with little variation throughout the entire basin. The data shows that Bakken crude is similar to other light crudes in average API gravity, average vapor pressure, a flashpoint below 73° Fahrenheit, average initial boiling point, and average sulfur weight. These characteristics fall within the design thresholds for the current DOT-111 tanker car. According to the NDPC, this study confirmed that Bakken crude is not significantly differed from other crude oil and poses no greater risks than other Class 3 flammable liquids authorized for rail transport.
Transportation of crude oil by rail has increased dramatically with the development of shale oil plays throughout the United States. According to the U.S. Energy Information Administration, nearly 1.4 million barrels per day of petroleum products were transported by rail in the first half of 2013, an increase of nearly 50% over the 927,000 barrels shipped in the first half of 2012.
For additional information on the transportation of crude oil by rail, visit some of our previous blog posts:
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
These studies in part respond to a safety alert issued on January 2, 2014, by the Pipeline and Hazardous Materials Safety Administration (PHMSA), which notified “the general public, emergency responders, and shippers and carriers that recent derailments and resulting fires indicate that the type of crude oil being transported from the Bakken region may be more flammable than traditional heavy crude oil.”
The May 14, 2014 report prepared for AFPM presents testing data that demonstrates that “Bakken crude is well within the safety standards for current rail car designs.” The data also shows that “Bakken crude is comparable to other light crudes and does not pose risks that are significantly different than other crudes of flammable liquids authorized for rail transport.”
Because Bakken crude is within the regulatory limits for pressure, flashpoint, boiling point and corrosivity for use in Department of Transportation (DOT) approved railcars, AFPM concludes that Bakken crude is a Class 3 Flammable Liquid and there is no need to create a new DOT classification for crude oil transportation.
At a conference on May 20, 2014, the NDPC released a study in which Bakken crude was found to be a typical Class 3 flammable liquid, with little variation throughout the entire basin. The data shows that Bakken crude is similar to other light crudes in average API gravity, average vapor pressure, a flashpoint below 73° Fahrenheit, average initial boiling point, and average sulfur weight. These characteristics fall within the design thresholds for the current DOT-111 tanker car. According to the NDPC, this study confirmed that Bakken crude is not significantly differed from other crude oil and poses no greater risks than other Class 3 flammable liquids authorized for rail transport.
Transportation of crude oil by rail has increased dramatically with the development of shale oil plays throughout the United States. According to the U.S. Energy Information Administration, nearly 1.4 million barrels per day of petroleum products were transported by rail in the first half of 2013, an increase of nearly 50% over the 927,000 barrels shipped in the first half of 2012.
For additional information on the transportation of crude oil by rail, visit some of our previous blog posts:
- Three oil companies voluntarily provide Bakken crude oil testing information to U.S. Department of Transportation
- U.S. Department of Transportation meets with oil and rail industry leaders to discuss transport safety issues
- U.S. Department of Transportation issues emergency order concerning trains carrying Bakken crude oil
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
Federal Judge in North Dakota dismisses thirteen gas-flaring royalty lawsuits
On May 14, 2014, US District Judge Daniel L. Hovland dismissed thirteen proposed class actions in which the plaintiffs sought payment of royalties for gas that was flared by oil and gas companies after flaring was permitted by North Dakota statute. The Judge ruled that the US District Court did not have subject matter jurisdiction because the plaintiffs had not exhausted their administrative remedies through the North Dakota Industrial Commission, the state agency that regulates oil and gas activities, including flaring violations.
The plaintiffs did not file a complaint with the Industrial Commission, arguing that exhaustion of administrative remedies was not required because the primary issues in the lawsuits concerned statutory construction or pure questions of law.
The Court disagreed, stating that the cases rest “upon the resolution of fairly technical and complex questions of fact and law,” including “(1) the volume of gas flared…, (2) the value of such flared gas; and (3) the application of the relevant Industrial Commission orders that pertain to each well.” The Court concluded that “[n]o decision-maker is better equipped to resolve such issues than the Industrial Commission itself which is possessed of the authority, experience and expertise to make such determinations.”
While recognizing “this may not be the Plaintiff’s preferred remedy, but it is the remedy nonetheless…,” the Court found no implied private right of action that would make the administrative remedy moot and that the plaintiffs could appeal any adverse decision from the NDIC in court.
Here is a copy of the order in one of the thirteen lawsuits, Scott Wisdhal, et al. v. XTO Energy, Inc., Case No. 4:13-cv-136, In the US District Court for the District of North Dakota, Northwestern Division. For additional information on all thirteen lawsuits, see the White Paper: Analysis of Litigation Involving Shale and Hydraulic Fracturing which is attached to this blog.
It should be noted that a fourteenth lawsuit based on the same allegations is in state court, Vogel, et al. v. Marathon Oil Company, Case No. 31-2013-cv-00163 (In District Court of Mountrail County, North Dakota, Northwest Judicial District).
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
The plaintiffs did not file a complaint with the Industrial Commission, arguing that exhaustion of administrative remedies was not required because the primary issues in the lawsuits concerned statutory construction or pure questions of law.
The Court disagreed, stating that the cases rest “upon the resolution of fairly technical and complex questions of fact and law,” including “(1) the volume of gas flared…, (2) the value of such flared gas; and (3) the application of the relevant Industrial Commission orders that pertain to each well.” The Court concluded that “[n]o decision-maker is better equipped to resolve such issues than the Industrial Commission itself which is possessed of the authority, experience and expertise to make such determinations.”
While recognizing “this may not be the Plaintiff’s preferred remedy, but it is the remedy nonetheless…,” the Court found no implied private right of action that would make the administrative remedy moot and that the plaintiffs could appeal any adverse decision from the NDIC in court.
Here is a copy of the order in one of the thirteen lawsuits, Scott Wisdhal, et al. v. XTO Energy, Inc., Case No. 4:13-cv-136, In the US District Court for the District of North Dakota, Northwestern Division. For additional information on all thirteen lawsuits, see the White Paper: Analysis of Litigation Involving Shale and Hydraulic Fracturing which is attached to this blog.
It should be noted that a fourteenth lawsuit based on the same allegations is in state court, Vogel, et al. v. Marathon Oil Company, Case No. 31-2013-cv-00163 (In District Court of Mountrail County, North Dakota, Northwest Judicial District).
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
EPA reviews states’ solid waste management regulations for oil and gas operations
In an April 1, 2014 memorandum, the U.S. Environmental Protection Agency (EPA) summarized state regulatory programs concerning the management of solid waste from oil and natural gas exploration, development and production (E&P) operations.
In reviewing each state’s regulations, the EPA focused on surface storage and disposal facilities managing produced waters, drilling muds, drilling cuttings, hydraulic fracturing return fluids, and various other waste liquids and materials intrinsically related to oil and gas E&P.
The EPA found that the state regulations were primarily concerned with the “technical requirements associated with the design, construction, operation, maintenance, closure, and reclamation of surface pits, ponds, lagoons or tanks, as well as financial assurance requirements associated with such facilities.”
Among the common parameters are state requirements for liners in pits and impoundments, secondary containment requirements for tanks, set-back requirements, and various inspection requirements. However, the EPA did find gaps in regulations relating to groundwater monitoring, leachate collection, air monitoring, and waste characterization.
Overall, with the review, the EPA had developed an understanding of the wide-range of state regulatory programs currently in place in the twenty-six (26) oil and gas producing states covered in the summary.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
In reviewing each state’s regulations, the EPA focused on surface storage and disposal facilities managing produced waters, drilling muds, drilling cuttings, hydraulic fracturing return fluids, and various other waste liquids and materials intrinsically related to oil and gas E&P.
The EPA found that the state regulations were primarily concerned with the “technical requirements associated with the design, construction, operation, maintenance, closure, and reclamation of surface pits, ponds, lagoons or tanks, as well as financial assurance requirements associated with such facilities.”
Among the common parameters are state requirements for liners in pits and impoundments, secondary containment requirements for tanks, set-back requirements, and various inspection requirements. However, the EPA did find gaps in regulations relating to groundwater monitoring, leachate collection, air monitoring, and waste characterization.
Overall, with the review, the EPA had developed an understanding of the wide-range of state regulatory programs currently in place in the twenty-six (26) oil and gas producing states covered in the summary.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
Three oil companies voluntarily provide Bakken crude oil testing information to U.S. Department of Transportation
On May 2, 2014, the U.S. Department of Transportation (USDOT) announced that three oil and gas companies voluntarily provided testing data on the crude oil that they ship from North Dakota’s Bakken Shale. This data was supplied in response to the USDOT’s call for action in January 2014, asking that oil companies, shippers, railroads, and industry stakeholders focus on ways to improve accident prevention and mitigation.
The USDOT’s announcement follows months of evaluation and discussions relating to recent train derailments of tanker cars carrying Bakken crude oil, including incidents in Minnesota, Maryland, Pennsylvania, North Dakota, and at three sites in Canada, including Lac-Mégantic (where 47 people were killed). Since the Lac-Mégantic accident, both Canadian and U.S. agencies have urged rail safety and have issued several alerts and rules regarding the shipping of crude oil.
For additional information on the transportation of crude oil by rail, click here and here.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
The USDOT’s announcement follows months of evaluation and discussions relating to recent train derailments of tanker cars carrying Bakken crude oil, including incidents in Minnesota, Maryland, Pennsylvania, North Dakota, and at three sites in Canada, including Lac-Mégantic (where 47 people were killed). Since the Lac-Mégantic accident, both Canadian and U.S. agencies have urged rail safety and have issued several alerts and rules regarding the shipping of crude oil.
- On September 6, 2013, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published a proposed rule concerning “Hazardous Materials: Rail Petitions and Recommendations to Improve the Safety of Railroad Tank Car Transportation (RRR).” This proposed rule imposes requirements for DOT Specification 111 tank cars used to transport Packing Group (PG) I and II hazardous materials.
- In November 2013, PHMSA and the Federal Railroad Administration (FRA) issued a joint safety alert to reinforce “the importance of proper characterization, classification, and selection” of the hazardous materials being transported. PHMSA issued a safety alert on January 2, 2014, “to notify the general public, emergency responders, and shippers and carriers that recent derailments and resulting fires indicate that the type of crude oil being transported from the Bakken region may be more flammable than traditional heavy crude oil.”
- On February 21, 2014, the USDOT and the Association of American Railroads (AAR) announced a rail safety initiative to institute new voluntary operating practices for moving crude oil by rails.
- On February 25, 2014, the U.S. Department of Transportation (DOT) issued an emergency order requiring rail shippers of crude oil to test the crude’s makeup before shipping it and to classify the crude as Packing Group I (high danger) or Packing Group II (medium danger) hazardous material until further notice.
- In April 2014, Canada’s Ministry of Transport issued Protective Direction No. 34 requiring the immediate phase out of the least crash-resistant DOT-111 tank cars from dangerous goods service. Along with Protective Direction, the Ministry issued an Emergency Directive and a Ministerial Order outlining further requirements, including maximum speeds for trains carrying one or more cars of crude oil and ordering a risk assessment for each train route.
For additional information on the transportation of crude oil by rail, click here and here.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
Wrongful death lawsuits, by-pass routes and first responder training – Issues relating to the transport of oil products by rail
Nineteen wrongful death lawsuits from the July 2013 train derailment and explosion in Lac-Mégantic, Quebec, Canada were transferred from U.S. District Court in Illinois to the U.S. District Court in Maine on March 21, 2014.
The Maine federal judge ordering the transfer found that these lawsuits were “related to” the Maine bankruptcy proceedings filed by Montreal Maine and Atlantic Railroad Ltd. (MMAR) one month after the accident. Presented with evidence of shared insurance between MMAR and some of the wrongful death defendants, the Court made the “limited finding that claims against certain of the defendants named therein are related to the Railway’s bankruptcy.”
Concerns about the safety of transporting oil by rail have increased following a number of recent accidents, including the Lac-Mégantic incident in which more than 40 died, a December 30, 2013 derailment of 21 tank cars in Casselton, North Dakota resulting in an explosion which required the evacuation of 1,400 people, and a November 8, 2013 derailment of more than 20 cars in a 90-car petroleum crude oil train near Aliceville, Alabama.
Approximately one-quarter of the nation’s rail traffic (about 40,000 cars) passes through Chicago on a daily basis, with some freight cars taking more than 24-hours to complete the transit through the city. With an increasing role in oil transport logistics, a 150-mile by-pass around Chicago has been suggested. The by-pass would require the laying of new track, raising the issue of funding. It would not be economically feasible for one railroad to fund the by-pass, and Chicago’s mayor’s recommendation to charge a fee for each rail car carrying hazardous materials was quickly criticized by railroad organizations.
The Maine federal judge ordering the transfer found that these lawsuits were “related to” the Maine bankruptcy proceedings filed by Montreal Maine and Atlantic Railroad Ltd. (MMAR) one month after the accident. Presented with evidence of shared insurance between MMAR and some of the wrongful death defendants, the Court made the “limited finding that claims against certain of the defendants named therein are related to the Railway’s bankruptcy.”
Concerns about the safety of transporting oil by rail have increased following a number of recent accidents, including the Lac-Mégantic incident in which more than 40 died, a December 30, 2013 derailment of 21 tank cars in Casselton, North Dakota resulting in an explosion which required the evacuation of 1,400 people, and a November 8, 2013 derailment of more than 20 cars in a 90-car petroleum crude oil train near Aliceville, Alabama.
Approximately one-quarter of the nation’s rail traffic (about 40,000 cars) passes through Chicago on a daily basis, with some freight cars taking more than 24-hours to complete the transit through the city. With an increasing role in oil transport logistics, a 150-mile by-pass around Chicago has been suggested. The by-pass would require the laying of new track, raising the issue of funding. It would not be economically feasible for one railroad to fund the by-pass, and Chicago’s mayor’s recommendation to charge a fee for each rail car carrying hazardous materials was quickly criticized by railroad organizations.
On March 25, 2014, the Fire Chief of Casselton (North Dakota) Volunteer Fire Department testified before the Senate Homeland Security and Government Affairs Committee concerning his experience with the crude oil train derailment near the town. Chief Tim McLean expressed his gratitude for the training he received and the fire equipment purchased using federal homeland security grant dollars, and he emphasized the need to continue that funding. “Because of the growing oil industry and the likelihood that oil will continue to be shipped via rail, we must continue to train and plan for these types of incidents. Yes…the tanker cars will likely be improved and pipelines may be used more extensively, but that does not erase the fact that crude oil and other hazardous materials will continue to be shipped through our communities. Our responder community must be ready for that.”
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
North Dakota approves flare reduction recommendations
The North Dakota Industrial Commission adopted several recommendations from the Department of Mineral Resources to reduce the amount of flaring in the state. These recommendations were based on work of the North Dakota Petroleum Council (NDPC) Flaring Task Force that was formed to study ways to increase the capture of flared gas. In December 2013, North Dakota flared 36% of its produced natural gas. The NDPC estimates that, by adopting these recommendations, North Dakota could increase natural gas capture to 85% within two years, 90% within six years, and up to 95% thereafter.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
The recommendations include:
- After June 1, 2014, before filing an application for a drilling permit, upstream (producers) and midstream companies (natural gas processors and gatherers) would be required to create a Gas Capture Plan (GCP). Each GCP would include a location of the well and closest pipeline and processing plant; the system capacity of gathering and transport gas lines; the volume of gas flowing from multi-well pads; and a time period for connection. The companies must attach an affidavit that the GCP was provided to gathering companies in the area.
- A GCP is required for all future increased density, temporary spacing and proper spacing cases.
- A failure to submit a GCP may result in a denial or suspension of new drilling permits, while existing wells may be required to restrict production pending compliance.
- A web-based pipeline incident report form should be developed to provide landowners with an easy notification system for problems and concerns.
- There should be semi-annual meetings with gathering companies to determine the effect of the GCPs, production curtailments, contracts, and service interruptions.
- There should be a docket for hearing a motion to review and revise all Bakken and Three Forks field rules governing production curtailment.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
Emergency order requires testing and classification of crude oil transported by rail
On February 25, 2014, the U.S. Department of Transportation (DOT) issued an emergency order requiring rail shippers of crude oil to test the crude’s makeup before shipping it and to classify the crude as Packing Group I (high danger) or Packing Group II (medium danger) hazardous material until further notice.
The DOT’s emergency order recognizes that the misclassification of petroleum crude oil as a Packing Group III (low danger) material is an “imminent hazard…that presents a substantial likelihood that death, serious illness, severe personal injury, or a substantial endangerment to health, property, or the environment may occur.” This order requires that any person who wants to ship by rail a “large bulk quantity of petroleum crude oil” must conduct testing to verify its classification and must retain these records. “At a minimum, the tests shall be capable of determining the petroleum crude oil’s flash point; boiling point; corrosivity to steel and aluminum; presence and content of compounds such as sulfur/hydrogen sulfide; percentage presence of flammable gases; and the vapor pressure at 50°C.” To further ensure safety, Packing Group III can no longer be used for crude oil, requiring crude to be classified as either Packing Group I or Packing Group II material, both of which require the use of a stronger tank car than Packing Group III.
This order results from the dramatic growth in the quantity of petroleum crude oil being shipped by rail in recent years, with the resulting increase of incidents involving trains carrying crude. Recent incidents include (a) a December 30, 2013 derailment of 21 tank cars in Casselton, North Dakota resulting in an explosion which required the evacuation of 1,400 people; (b) a November 8, 2013 derailment of more than 20 cars in a 90-car petroleum crude oil train near Aliceville, Alabama; and (c) the catastrophic accident in Lac-Mégantic, Quebec, Canada on July 6, 2013 when an unattended freight train derailed, resulting in multiple explosions and fires and the deaths of more than 40 people. The Canadian authorities investigating the Lac- Mégantic incident analyzed the Bakken petroleum crude oil from nine of the undamaged tank cars and found that the crude had been incorrectly labeled Packing Group III rather than Packing Group II.
In the months after these incidents, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and Federal Railroad Administration (FRA) have issued several safety alerts and advisories, including:-
For additional information on Operation Classification, click here; and for information on meetings between the DOT and representatives of the railroads and oil industry, click here.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
The DOT’s emergency order recognizes that the misclassification of petroleum crude oil as a Packing Group III (low danger) material is an “imminent hazard…that presents a substantial likelihood that death, serious illness, severe personal injury, or a substantial endangerment to health, property, or the environment may occur.” This order requires that any person who wants to ship by rail a “large bulk quantity of petroleum crude oil” must conduct testing to verify its classification and must retain these records. “At a minimum, the tests shall be capable of determining the petroleum crude oil’s flash point; boiling point; corrosivity to steel and aluminum; presence and content of compounds such as sulfur/hydrogen sulfide; percentage presence of flammable gases; and the vapor pressure at 50°C.” To further ensure safety, Packing Group III can no longer be used for crude oil, requiring crude to be classified as either Packing Group I or Packing Group II material, both of which require the use of a stronger tank car than Packing Group III.
This order results from the dramatic growth in the quantity of petroleum crude oil being shipped by rail in recent years, with the resulting increase of incidents involving trains carrying crude. Recent incidents include (a) a December 30, 2013 derailment of 21 tank cars in Casselton, North Dakota resulting in an explosion which required the evacuation of 1,400 people; (b) a November 8, 2013 derailment of more than 20 cars in a 90-car petroleum crude oil train near Aliceville, Alabama; and (c) the catastrophic accident in Lac-Mégantic, Quebec, Canada on July 6, 2013 when an unattended freight train derailed, resulting in multiple explosions and fires and the deaths of more than 40 people. The Canadian authorities investigating the Lac- Mégantic incident analyzed the Bakken petroleum crude oil from nine of the undamaged tank cars and found that the crude had been incorrectly labeled Packing Group III rather than Packing Group II.
In the months after these incidents, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and Federal Railroad Administration (FRA) have issued several safety alerts and advisories, including:-
- FRA’s Emergency Order No. 28 (EO 28) establishing securement requirements for certain unattended trains and rail equipment, including petroleum crude oil unit trains;
- PHMSA and FRA’s Safety Advisory 2013-06 recommending that railroads and shippers evaluate their processes to ensure that hazardous materials such as petroleum crude oil be properly classed and described and that safety and security plans be reviewed; and
- PHMSA and FRA’s supplemental Safety Advisory 2013-07 emphasizing the importance of proper characterization, classification, and selection of Packing Group for the crude being shipped.
For additional information on Operation Classification, click here; and for information on meetings between the DOT and representatives of the railroads and oil industry, click here.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
U.S. Department of Transportation meets with oil and rail industry leaders to discuss transport safety issues
With the recent December 30, 2013 derailment of tanker cars
carrying oil in Casselton, North Dakota, as well as other 2013 incidents
in western Minnesota, Baltimore, Alabama, and at three sites in Canada
(Gainfield, Landis, and Lac-Mégantic, where 47 people were killed when
an unattended 72-car freight train derailed in the center of town), the
U.S. Department of Transportation (DOT) met with representatives from the oil
and railroad industries to discuss transport safety issues relating to crude
oil.
At the meeting on January 15, 2014, representatives from the
American Petroleum Institute (API) and the Association of American Railroads
(AAR) reportedly agreed to take steps to avoid derailments, to work on a speed
reduction plan, and to re-route trains around high-risk areas. According to the
AAR representative, 27 risk factors, including population density, volume of hazardous materials
being transported, and traffic density, are always considered when
routing trains. The API representative stressed the importance of having
strong rail cars to transport the crude oil.
On September 6, 2013, in the Federal Register, the Pipeline
and Hazardous Materials Safety Administration (PHMSA) published a proposed rule concerning “Hazardous Materials: Rail Petitions and Recommendations to
Improve the Safety of Railroad Tank Car Transportation (RRR).This
proposed rule would impose additional requirements for DOT Specification
111 tank cars used to transport Packing Group (PG) I and II hazardous
materials. PHMSA has indicated that the proposed rule relating to
the construction of rail tanker cars will not be finalized until at least
January 2015.
With the volume of produced
oil rising faster than can be moved by pipeline, railroads are being used more
and more to transport oil products to processing facilities – and with that
increase, come increasing concerns about the safety of transporting
crude oil by rail.
In early January, PHMSA and the Federal Railroad
Administration issued a safety alert “to notify
the general public, emergency responders, and shippers and carriers that recent
derailments and resulting fires indicate that the type of crude oil being
transported from the Bakken region may be more flammable than traditional heavy
crude oil.” For additional information, see our prior blog
entitled “Safety alert relating to flammability of North Dakota Bakken crude oil transported by rail.”
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
Safety alert relating to flammability of North Dakota Bakken crude oil transported by rail
On December 30, 2013, near the town of Casselton, North Dakota, a westbound train carrying grain derailed. Within minutes, an eastbound 106-car train transporting Bakken crude oil hit the derailed train. The collision caused eighteen oil cars to leave the tracks and catch fire. While no one was hurt, many of the town’s 2,400 residents temporarily evacuated their homes for two days due to explosions, intense flames, and heavy smoke from the burning cars.
Taking note of this and other similar incidents involving trains carrying crude oil (see below), the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a safety alert on January 2, 2014, “to notify the general public, emergency responders, and shippers and carriers that recent derailments and resulting fires indicate that the type of crude oil being transported from the Bakken region may be more flammable than traditional heavy crude oil.”
This alert follows a joint safety alert from PHMSA and the Federal Railroad Administration (FRA) dated November 20, 2013, to reinforce “the importance of proper characterization, classification, and selection of a hazardous materials packing group as required by the Federal hazardous materials law (49 U.S.C. 5101-5128) and Hazardous Materials Regulations (HMR; 49 CFR parts 171-180).” PHMSA and FRA have initiated an “Operation Classification” program in which there will be “unannounced inspections and testing of crude oil samples to verify that…the materials have been properly classified…”
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
Taking note of this and other similar incidents involving trains carrying crude oil (see below), the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a safety alert on January 2, 2014, “to notify the general public, emergency responders, and shippers and carriers that recent derailments and resulting fires indicate that the type of crude oil being transported from the Bakken region may be more flammable than traditional heavy crude oil.”
This alert follows a joint safety alert from PHMSA and the Federal Railroad Administration (FRA) dated November 20, 2013, to reinforce “the importance of proper characterization, classification, and selection of a hazardous materials packing group as required by the Federal hazardous materials law (49 U.S.C. 5101-5128) and Hazardous Materials Regulations (HMR; 49 CFR parts 171-180).” PHMSA and FRA have initiated an “Operation Classification” program in which there will be “unannounced inspections and testing of crude oil samples to verify that…the materials have been properly classified…”
With the volume of produced oil rising faster than can be moved by pipeline, railroads are being used more and more to transport oil products to processing facilities. The Energy Information Administration estimates that 1.37 million barrels per day of oil and petroleum products were shipped on railways during the first six months of 2013, that is approximately 356,000 carloads, up 48% from the same period in 2012. Review the numbers. This increased volume has led to an increase in the number of oil-related accidents. Since April of 2013, there have been oil tanker derailments in western Minnesota, Baltimore, and at three sites in Canada: Lac-Mégantic, Gainfield, and Landis.
In the Lac-Mégantic incident, on July 6, 2013, an unattended 72-car freight train wrecked in the center of the small town, rupturing many of the tanker cars, and causing a fire approximately 400 feet in diameter. Forty-seven people died in the explosion and fire. See article.
On October 17, 2013, the Canadian government imposed new regulations requiring tests to be conducted on crude oil before transporting or importing it into Canada. In the Lac- Mégantic crash, inspectors determined that the oil the train carried was more explosive than labeled. See David Ljunggren, “Fuel on train in Quebec disaster more explosive than labeled,” Reuters Canada.
In the Lac-Mégantic incident, on July 6, 2013, an unattended 72-car freight train wrecked in the center of the small town, rupturing many of the tanker cars, and causing a fire approximately 400 feet in diameter. Forty-seven people died in the explosion and fire. See article.
On October 17, 2013, the Canadian government imposed new regulations requiring tests to be conducted on crude oil before transporting or importing it into Canada. In the Lac- Mégantic crash, inspectors determined that the oil the train carried was more explosive than labeled. See David Ljunggren, “Fuel on train in Quebec disaster more explosive than labeled,” Reuters Canada.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
International Energy Agency predicts that the US will become world's top energy producer in 2015 but will relinquish that position by 2020
The International Energy Agency (IEA), which was formed in the 1970s to keep track of trends and improve energy security, released its World Energy Outlook 2013 in London on November 12, 2013. The 2013 Outlook provides a review of key trends that IEA believes will shape the future of global energy through 2035. For the US, the IEA projects that it will pass Saudi Arabia and Russia as the world’s top oil producer by 2015 due to the use of hydraulic fracturing and other unconventional technologies in developing its shale gas resources. This will bring the US closer to energy self-sufficiency. But, according to the IEA, the US will lose its dominant position by 2020 due to decline in production from Texas and North Dakota fields. Continuous investment in drilling new wells will be required to compensate for the declines in existing wells and to maintain a high output. For the countries seeking to replicate the success of the US with hydraulic fracturing, the IEA cautions that “good geology alone is not sufficient.” These countries do not have the US’s legal environment and oil services capabilities to make shale oil and gas development worth the cost.
Other key trends noted in IEA’s World Energy Outlook 2013 include:
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
Other key trends noted in IEA’s World Energy Outlook 2013 include:
- After 2020, Middle East oil will regain its dominance.
- By 2020, China will be the largest oil-consuming country, overtaking the US
- Fossil fuels will be providing 75% of global energy by 2035.
- Demand for oil will increase 27% between 2012 and 2035, to 111 million barrels per day.
- Demand in the US, Europe and other developed countries will decrease between 2013 and 2035 due to improved energy efficiencies, such as tougher automotive fuel standards.
- Oil use is increasingly concentrated in transport and petrochemicals.
- The demand for diesel will grow three times faster than the demand for gasoline.
- Over the past ten years, more super-giant off-shore fields have been discovered in Brazil than in any other country. By 2035, Brazil will produce 6 million barrels of oil per day and become the world’s sixth largest oil producer.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
North Dakota mineral owners file ten class actions relating to royalties owed for flaring natural gas
Ten class actions were filed in North Dakota by mineral
owners alleging lost income due to the flaring of natural gas by various oil
and gas producers. According to a July 2013 report by Ceres, the flaring of natural gas in North Dakota has
doubled in the past two years.
The lawsuits allege that the producers have violated
several North Dakota Industrial Commission rules relating to flaring and paying
royalties for flared gas. After an oil well begins to produce, North
Dakota allows limited flaring during the first year. After one year, the
producer must apply for a written exemption for any future flaring. If
the producer does not ask for the exemption, royalties and state taxes on the
flared gas must be paid.
The lawsuits allege that these various producers have flared gas without the proper authorization and therefore, owe royalties on “(a) gas flared from a well one year after the first production without applying for and obtaining a flaring exemption; (b) gas flared from a well within the first year of production under an order issued by the Industrial Commission limiting the maximum barrels of oil to be produced per day until the well is connected to a gathering system and processing plant…; and (c) gas flared within the first year of production even though the operator reported the well was physically connected to a gathering system and processing plant.”
The plaintiffs claim that they lost millions of dollars in royalties due to producers’ practice of burning off large quantities of gas rather than selling it.
The lawsuits allege that these various producers have flared gas without the proper authorization and therefore, owe royalties on “(a) gas flared from a well one year after the first production without applying for and obtaining a flaring exemption; (b) gas flared from a well within the first year of production under an order issued by the Industrial Commission limiting the maximum barrels of oil to be produced per day until the well is connected to a gathering system and processing plant…; and (c) gas flared within the first year of production even though the operator reported the well was physically connected to a gathering system and processing plant.”
The plaintiffs claim that they lost millions of dollars in royalties due to producers’ practice of burning off large quantities of gas rather than selling it.
For an example of one of these ten class actions, see
attached case filed in District Court, Northwest Judicial District, County of
Williams, State of North Dakota.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
USGS assesses undiscovered oil resources in Bakken and Three Forks Formations
The U.S. Geological Survey (USGS) recently completed a geology-based assessment of the oil and gas resources of the Bakken and Three Forks Formations, located in North Dakota, Montana, and South Dakota, finding that these formations together hold an estimated mean of 7.38 billion barrels of oil, 6.7 trillion cubic feet (tcf) of gas, and 0.53 billion barrels of natural gas liquids. See USGS Fact Sheet 2013–3013: Assessment of Undiscovered Oil Resources in the Bakken and Three Forks Formations, Williston Basin Province, Montana, North Dakota, and South Dakota, 2013. The Three Forks Formation was found to have 3.73 billion barrels of estimated mean resource of oil, with the Bakken Formation having a 3.65 billion barrels (approximately the same amount as was found in the USGS’ 2008 assessment of the Bakken Formation). The formations combined estimate ranges from 4.42 million barrels with a 95% change of production to 11.43 billion barrels with a 5% chance. Gas estimates ranged from 3.43 tcf (with a 95% chance of production) to 11.25 tcf (with a 5% chance) and 0.23 billion barrels (95%) to 0.95 billion barrels (5%) of natural gas liquids. This assessment was undertaken as part of the USGS’ nationwide project to assess U.S. petroleum basins using standardized methodology and protocol. Data for this assessment was provided by the North Dakota Geological Survey, North Dakota Industrial Commission, Montana Board of Oil and Gas, and multiple industry groups working in the formations.
This article was prepared by Barclay Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice Group.
This article was prepared by Barclay Nicholson (bnicholson@fulbright.com or 713 651 3662) from Fulbright's Energy Practice Group.
Survey of Flaring Regs for Arkansas, Colorado, Louisiana, North Dakota, Pennsylvania, Texas and Wyoming
Natural gas production is booming in the United States.
Operators, aided by advances in hydraulic fracturing, have ramped up production, whether by reworking old oil wells or exploiting new formations altogether.
However, just because an operator has the ability to produce natural gas does not necessarily mean that it can sell the gas; compressors, pipelines, treatment plants, and other infrastructure must be prepared in order to get the gas to market.
However, just because an operator has the ability to produce natural gas does not necessarily mean that it can sell the gas; compressors, pipelines, treatment plants, and other infrastructure must be prepared in order to get the gas to market.
In some cases, this lack of infrastructure has led operators to vent or flare gas at the wellhead.
In order to get a better understanding of where the law stands and in what direction it may head, below is a survey of the major gas-producing states’ regulations regarding flaring.
Note: this survey covers only the regulations that speak directly to the question of whether an operator may flare the gas on private lands. Flaring has other potential legal repercussions, such as the particles that are emitted in the process that could call into question state or federal clean air laws or endangered species, and different regulations apply to wells located on state- or federally-owned land. Those concerns are beyond the scope of this survey.
Arkansas
Arkansas allows operators to vent or flare gas within 7 days of when gas is first encountered in a well. After that time, gas may not be vented or flared unless the operator obtains an exception from the Arkansas Oil and Gas Commission.Colorado
In Colorado, all flaring must be authorized by the Colorado Oil and Gas Conservation Commission unless it is done during an upset condition, well maintenance, well stimulation flowback, purging operations, or a productivity test.Louisiana
In Louisiana, flaring of natural gas is prohibited unless the Louisiana Office of Conservation finds upon written application that such a prohibition would result in an economic hardship on the operator. The regulations further note that no such economic hardship can be found if the current market value—at the point of delivery for the gas proposed to be vented—exceeds the cost involved in making the gas available to market.North Dakota
Gas may be flared during the first year of production from a well. N.D. Century code 38-08-06.4. After the one-year grace period, the well must be either connected to a pipeline or used at the wellhead to power an electrical generator, unless the producer applies for and obtains an exception. Id.
Producers can obtain exceptions from the Industrial Commission for additional flaring if the producer presents evidence demonstrating the economic infeasibility of piping gas from the well. Id.
It is economically infeasible to connect the well to a natural gas gathering line if the direct costs of connecting the well to the line and the direct costs of operating the facilities connecting the well to the line during the life of the well are greater than the amount of money the operator is likely to receive for the gas, less production taxes and royalties, should the well be connected to the gathering line. N.D. Century Code 43-02-03-60.2.
Oklahoma
In Oklahoma, an operator may vent or flare up to 50 mcf/day without a permit if: (i) it is not economically feasible to market the gas; (ii) a suitable stand, line, or stack is used to prevent a hazard to people; and (iii) there is less than 100 ppm of hydrogen sulfide in the gas. For venting or flaring at rate greater than 50 mcf/day, the operator must seek an administrative permit from the Conservation Division of the Oklahoma Corporation Commission.Pennsylvania
Pennsylvania’s oil and gas conservation regulations do not address flaring, other than to say that it may be done so long as it does not endanger people.Texas
Texas producers have a grace period of 10 days after the initial completion, recompletion in another field, or workover operations in the same field, during which they may flare natural gas. 16 TAC 3.32(f)(1)(A). Releases of gas that are not routinely measured (such as small amounts that escape during the initial completion of a well) are exempt from flaring requirements and need not be measured for the purposes of well allowables. 16 TAC 3.32 (d)(1).
Producers may also vent or flare gas when a well must be unloaded or cleaned-up to atmospheric pressure, but may only do so for fewer than 24 hours in one continuous event or a total of 72 hours in one calendar month. 16 TAC 3.32(f)(1)(B). Texas producers may obtain exceptions from the railroad commission for the release of gas when the operator presents information to show the necessity of the release. 16 TAC 3.322(f)(2).
However, such administrative exceptions shall not be granted for periods exceeding 180 days, though they may be renewed. 16 TAC 3.32(h).
Wyoming
Wyoming allows for flaring without any additional regulatory authorization in the following situations:- During emergencies or upset conditions, which are temporary situations that result in the unavoidable short-term venting or flaring of gas;
- For well purging and evaluation tests;
- During initial or recompletion evaluation tests which shall not exceed 15 days unless otherwise authorized; or
- If it is a venting or flaring of casinghead gas from an oil well that produces less than 60 MCF of gas per day, unless the Wyoming Oil & Gas Conservation Commission determines that waste is occurring.
Texas RRC Press Release, May 23, 2012
Texas Railroad Commissioner David Porter discussed the possibility of new regulations in a May 23 news release. Noting that gas drilling activity “is outstripping capacity and awaiting pipeline infrastructure,” Commissioner Porter asserted that Texas “must proactively address flaring.” The only specifics provided in the news release were:
- that the Railroad Commission is seeking to work in partnership with Texas electrical energy regulators to use excess gas for strategic generation in light of the threat of weather-induced power curtailment; and
- that the Railroad Commission is studying a pilot program for using gas as a source of power for on-lease operations in lieu of flaring the gas.
This article was prepared by Barclay Nicholson (bnicholson@fulbright.com / 713 651 3662) from Fulbright's Energy Law Practice.
Texas, Other States Move Forward With Hydraulic Fracturing Disclosure Regulations
Earlier this year, Texas became the latest state to draft regulations requiring the disclosure of chemicals used in the hydraulic fracturing process. Michigan and Montana issued similar regulations over the summer, joining Arkansas, Wyoming, and Pennsylvania as states recently active in regulating hydraulic fracturing.[1] The new regulations require specific disclosures by operators and outline requirements for construction and operation of the well and continued monitoring of well activity. Three additional states, Louisiana, New York, and North Dakota, have proposed regulations open for public comment. This briefing examines recent changes and additions in hydraulic fracturing regulations throughout the country.
On October 11, 2011, the public comment period closed for the proposed hydraulic fracturing chemical disclosure regulations issued by the Railroad Commission of Texas. The Railroad Commission issued the new regulations on September 9, pursuant to HB 3328, passed by the Texas Legislature in June.[2] HB 3328 requires that the approved regulations be effective by July 1, 2012; however, it is expected that regulations will be finalized by the end of the year.
The proposed Texas regulations require public disclosure of chemicals used in the fracturing process that are either regulated by OSHA or are otherwise intentionally added, along with the actual or maximum concentrations of each chemical.[3]
Michigan's Supervisor of Wells issued new regulations in May 2011, which became effective June 22, 2011.[4] Under the regulations, well completions for high volume hydraulic fracturing must include the Material Safety Data Sheet and the volume used for all additives. High volume hydraulic fracturing is defined as an operation that is intended to use a total of more than 100,000 gallons of hydraulic fracturing fluid.
Additional regulations apply to wells with large volume water withdrawals, defined as withdrawals with a cumulative total of over 100,000 gallons per day. For these wells, permit applications must include: a water withdrawal evaluation (and in some cases a site-specific review by the DEQ); the proposed total volume of water needed; the number of water withdrawal wells; well locations, depths, and proposed pumping rates and frequencies; any freshwater wells within 1,320 feet; and the locations and dimensions of proposed freshwater pits.
Texas: Public Comment Period Closed
On October 11, 2011, the public comment period closed for the proposed hydraulic fracturing chemical disclosure regulations issued by the Railroad Commission of Texas. The Railroad Commission issued the new regulations on September 9, pursuant to HB 3328, passed by the Texas Legislature in June.[2] HB 3328 requires that the approved regulations be effective by July 1, 2012; however, it is expected that regulations will be finalized by the end of the year.
The proposed Texas regulations require public disclosure of chemicals used in the fracturing process that are either regulated by OSHA or are otherwise intentionally added, along with the actual or maximum concentrations of each chemical.[3]
Companies would be required to use Chemical Abstracts Service (CAS) numbers to identify chemicals in the fracturing fluids, making the disclosure more transparent for shippers, suppliers, end users, and the public. The regulations specifically exempt from disclosure chemicals unintentionally added, chemicals that occur naturally, or chemicals not disclosed by the manufacturer, supplier, or service company.
Companies can also claim trade secret exemptions, which must be approved by the Railroad Commission. If a trade secret exemption is granted, only three parties can challenge it:
- the landowner on whose property the wellhead is located;
- any adjacent property owners; and
- government agencies.
Michigan: Regulations Effective June 22, 2011
Michigan's Supervisor of Wells issued new regulations in May 2011, which became effective June 22, 2011.[4] Under the regulations, well completions for high volume hydraulic fracturing must include the Material Safety Data Sheet and the volume used for all additives. High volume hydraulic fracturing is defined as an operation that is intended to use a total of more than 100,000 gallons of hydraulic fracturing fluid.
Additional regulations apply to wells with large volume water withdrawals, defined as withdrawals with a cumulative total of over 100,000 gallons per day. For these wells, permit applications must include: a water withdrawal evaluation (and in some cases a site-specific review by the DEQ); the proposed total volume of water needed; the number of water withdrawal wells; well locations, depths, and proposed pumping rates and frequencies; any freshwater wells within 1,320 feet; and the locations and dimensions of proposed freshwater pits.
If there is a freshwater well within 1,320 feet, a monitor well must be installed and monitored daily during water withdrawal, and weekly thereafter. During the withdrawal process, injection pressures must be recorded. Upon well completion, records and charts showing fracturing volume, rates, pressures, and the total volume of flowback water must be included in the record of well completion.
According to the Michigan Department of Environmental Quality, no current hydraulic fracturing activity in Michigan would qualify as high volume under the proposed regulations.[5]
According to the Michigan Department of Environmental Quality, no current hydraulic fracturing activity in Michigan would qualify as high volume under the proposed regulations.[5]
Existing wells, which are located on the Antrim Shale, are shallow and typically use only 50,000 gallons of water in the fracturing process. The regulations were implemented in anticipation of development on the Utica Shale, a deeper formation that would require much larger volumes of water use.
Montana: Regulations Effective August 27, 2011
The Montana Board of Oil and Gas issued new regulations that became effective August 27, 2011.[6] Under the Montana regulations, applications for permits must include the volumes and types of materials to be used in the proposed hydraulic fracturing activities. Principal components or chemicals must be identified by trade name or generic name.
Upon completion, fracturing operators must disclose the amounts and types of chemicals used, including the additive types, chemical ingredient names, and CAS numbers. Operators can qualify for trade secret exemptions, under which exempted chemicals must be identified by trade name, inventory name, chemical family name, or other unique name, and operators must disclose the quantity of the exempted chemical to be used. The regulations also require that permit applications include the processes to be used and the maximum anticipated treating pressure.
In addition to application requirements, the Montana regulations lay out specific structural and operational requirements. Fracturing wells must have a pressure relief valve and a remotely controlled shut-in device. Before stimulation, fracturing wells must undergo a casing pressure test. During the casing test, the maximum anticipated pressure must be applied for thirty minutes without the well losing more than ten percent of the pressure. Additionally, during operations, the annular space must be monitored. Upon completion, operators must describe the interval or formation treated and the amounts of maximum pressure during treatment.
In September 2011, the New York Department of Environmental Conservation issued extensive proposed regulations that outline permitting and operations requirements for hydraulic fracturing that uses more than 300,000 gallons of water cumulatively.[7] Under the proposed regulations, operators must follow the requirements of the application process for a normal drilling permit, as well as comply with State Pollutant Discharge Elimination System (SPDES) and Stormwater Pollutant Prevention (SWPP) plans. The New York regulations will be out for public comment through December 12, 2011.
To obtain a permit for hydraulic fracturing, operators must include the following information: the minimum and estimated maximum depths; the proposed volume of water and source of the water; distances from certain types of water supplies; identities of nearby abandoned wells; the engines and fuel to be used and air emission control measures; and information on blowout preventer measures. The New York regulations also contain detailed requirements for setbacks, water and pressure testing, casing structure, and construction, including site preparations and maintenance.
To comply with SPDES and SWPP requirements, operators must disclose particular information and submit plans aimed at preventing water contamination and sediment erosion. Operators must disclose: the proposed additives and each additive's proposed volume; copies of Material Safety Data Sheets for each product to be used; the proposed percent of water, proppants, and each additive product; documentation showing that the proposed additives have reduced aquatic toxicity and pose a lower potential risk to water resources and the environment than available alternatives (or that available alternative products are not equally effective or feasible); and the identification of the service company. Trade secret protection is available if granted by the Department of Environmental Conservation. Plans to prevent water contamination and sediment erosion require operators to continually monitor well activity, such as stormwater discharges, water usage, and flowback and produced water volumes. Operators must have certification for planned disposal methods, secondary containment measures, spill prevention plans, and methods to store flowback water.
On August 30, 2011, the Louisiana Department of Natural Resources released a proposed rule for public comment.[8] The rule requires operators upon well completion to disclose the types and volumes of the hydraulic fracturing fluid, a list of additives including trade names and suppliers, CAS numbers for hazardous chemicals, and maximum ingredient concentrations. The proposed rule has a provision for trade secret protection under which only the chemical family must be disclosed.
The Department of Natural Resources has not officially issued an anticipated effective date. According to reports, the rule is expected to become effective in October 2011.
The North Dakota Industrial Commission proposed new regulations for hydraulic fracturing on September 23, 2011.[9] Under the proposed rules, companies who do not use a frac string running inside the intermediate casing string must disclose the hydraulic fracturing fluid composition, including the trade name, supplier, ingredients, CAS number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. No disclosure is required for wells that use a frac string inside the intermediate casing string. The proposed rules also outline specific safety systems that must be used, including pressure relief valves, diversion lines, and remote operated frac valves. The North Dakota regulations are currently out for public comment, and a public hearing is scheduled for November 1.
This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) and Andrea Fair (afair@fulbright.com or 713 651 3782) from Fulbright's Litigation Department.
Learn more about Fulbright's Shale and Hydraulic Fracturing Task Force at www.fulbright.com/shale.
----
[1] See 25 Pa. Code §78.55 (as part of the permitting process, drilling companies must disclose the names of all chemicals to be stored and used at a drilling site in the Pollution Prevention and Contingency Plan submitted to the Department of Environmental Protection); Wy. Oil & Gas Comm'n § 3-8(c) (operators must disclose chemical additives and proposed concentrations in the Application for Permit to Drill or Deepen). Ariz. Admin. Code § 12-7-117 (operators of wells using "artificial stimulation" must report the amount and types of material injected within 15 days of the procedure).
[2] HB 3328, 2011 Leg., 82 Sess. (TX 2011). For an in-depth analysis of HB 3328 and the proposed Texas disclosure requirements, see Texas Legislature Joins Growing Number of States in Requiring Disclosure of Hydraulic Fracturing Fluids, Fulbright Briefing (June 16, 2011).
[3] 36 Tex. Reg. 5765 (2011) (to be codified at 16 Tex. Admin. Code § 3.29) (proposed September 9, 2011) (Railroad Commission of Texas).
[4] Supervisor of Wells Instruction 1-2011, High Volume Hydraulic Fracturing Well Completions, State of Michigan Department of Environmental Quality (May 23, 2011).
[5] Keith B. Hall, Michigan Issues New Hydraulic Fracturing Regulations, Oil & Gas Law Brief, Stone Pigman Walther Wittmann L.L.C.
[6] Administrative Rules of Montana, Title 36, Chapter 22.
[7] N.Y. Comp. Codes R. & Regs. tit. 6, Parts 52, 190, 550–556, 560, 750
[8] LAC 43:XIX Subpart 1, Chapter 1.
[9] N.D. Admin. Code § 43-02-03-27.1.
In addition to application requirements, the Montana regulations lay out specific structural and operational requirements. Fracturing wells must have a pressure relief valve and a remotely controlled shut-in device. Before stimulation, fracturing wells must undergo a casing pressure test. During the casing test, the maximum anticipated pressure must be applied for thirty minutes without the well losing more than ten percent of the pressure. Additionally, during operations, the annular space must be monitored. Upon completion, operators must describe the interval or formation treated and the amounts of maximum pressure during treatment.
New York: Out for Public Comment
In September 2011, the New York Department of Environmental Conservation issued extensive proposed regulations that outline permitting and operations requirements for hydraulic fracturing that uses more than 300,000 gallons of water cumulatively.[7] Under the proposed regulations, operators must follow the requirements of the application process for a normal drilling permit, as well as comply with State Pollutant Discharge Elimination System (SPDES) and Stormwater Pollutant Prevention (SWPP) plans. The New York regulations will be out for public comment through December 12, 2011.
To obtain a permit for hydraulic fracturing, operators must include the following information: the minimum and estimated maximum depths; the proposed volume of water and source of the water; distances from certain types of water supplies; identities of nearby abandoned wells; the engines and fuel to be used and air emission control measures; and information on blowout preventer measures. The New York regulations also contain detailed requirements for setbacks, water and pressure testing, casing structure, and construction, including site preparations and maintenance.
To comply with SPDES and SWPP requirements, operators must disclose particular information and submit plans aimed at preventing water contamination and sediment erosion. Operators must disclose: the proposed additives and each additive's proposed volume; copies of Material Safety Data Sheets for each product to be used; the proposed percent of water, proppants, and each additive product; documentation showing that the proposed additives have reduced aquatic toxicity and pose a lower potential risk to water resources and the environment than available alternatives (or that available alternative products are not equally effective or feasible); and the identification of the service company. Trade secret protection is available if granted by the Department of Environmental Conservation. Plans to prevent water contamination and sediment erosion require operators to continually monitor well activity, such as stormwater discharges, water usage, and flowback and produced water volumes. Operators must have certification for planned disposal methods, secondary containment measures, spill prevention plans, and methods to store flowback water.
Louisiana: Out for Public Comment
On August 30, 2011, the Louisiana Department of Natural Resources released a proposed rule for public comment.[8] The rule requires operators upon well completion to disclose the types and volumes of the hydraulic fracturing fluid, a list of additives including trade names and suppliers, CAS numbers for hazardous chemicals, and maximum ingredient concentrations. The proposed rule has a provision for trade secret protection under which only the chemical family must be disclosed.
The Department of Natural Resources has not officially issued an anticipated effective date. According to reports, the rule is expected to become effective in October 2011.
North Dakota: Out for Public Comment
The North Dakota Industrial Commission proposed new regulations for hydraulic fracturing on September 23, 2011.[9] Under the proposed rules, companies who do not use a frac string running inside the intermediate casing string must disclose the hydraulic fracturing fluid composition, including the trade name, supplier, ingredients, CAS number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. No disclosure is required for wells that use a frac string inside the intermediate casing string. The proposed rules also outline specific safety systems that must be used, including pressure relief valves, diversion lines, and remote operated frac valves. The North Dakota regulations are currently out for public comment, and a public hearing is scheduled for November 1.
This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) and Andrea Fair (afair@fulbright.com or 713 651 3782) from Fulbright's Litigation Department.
Learn more about Fulbright's Shale and Hydraulic Fracturing Task Force at www.fulbright.com/shale.
----
[1] See 25 Pa. Code §78.55 (as part of the permitting process, drilling companies must disclose the names of all chemicals to be stored and used at a drilling site in the Pollution Prevention and Contingency Plan submitted to the Department of Environmental Protection); Wy. Oil & Gas Comm'n § 3-8(c) (operators must disclose chemical additives and proposed concentrations in the Application for Permit to Drill or Deepen). Ariz. Admin. Code § 12-7-117 (operators of wells using "artificial stimulation" must report the amount and types of material injected within 15 days of the procedure).
[2] HB 3328, 2011 Leg., 82 Sess. (TX 2011). For an in-depth analysis of HB 3328 and the proposed Texas disclosure requirements, see Texas Legislature Joins Growing Number of States in Requiring Disclosure of Hydraulic Fracturing Fluids, Fulbright Briefing (June 16, 2011).
[3] 36 Tex. Reg. 5765 (2011) (to be codified at 16 Tex. Admin. Code § 3.29) (proposed September 9, 2011) (Railroad Commission of Texas).
[4] Supervisor of Wells Instruction 1-2011, High Volume Hydraulic Fracturing Well Completions, State of Michigan Department of Environmental Quality (May 23, 2011).
[5] Keith B. Hall, Michigan Issues New Hydraulic Fracturing Regulations, Oil & Gas Law Brief, Stone Pigman Walther Wittmann L.L.C.
[6] Administrative Rules of Montana, Title 36, Chapter 22.
[7] N.Y. Comp. Codes R. & Regs. tit. 6, Parts 52, 190, 550–556, 560, 750
[8] LAC 43:XIX Subpart 1, Chapter 1.
[9] N.D. Admin. Code § 43-02-03-27.1.
Subscribe to:
Posts (Atom)