Comments on Pennsylvania’s proposed surface operations rules

The comment period for the Pennsylvania’s Department of Environmental Protection’s proposed surface operations rules ended on March 14, 2014. These proposed rules would update Chapter 78 of the Pennsylvania Code relating to the construction and operation of oil and gas wells. The proposals focus on surface activities on and off well sites, such as waste handling, spill prevention, pipelines, pits and the protection of natural resources.

The Marcellus Shale Coalition (MSC), an advocate for the natural gas industry, indicated that compliance with the proposed regulations would cost drillers between $200 million and $300 million annually, much higher than the estimate of $75 million to $96.6 million made by the DEP.

This significant underestimation indicates that the DEP “has failed to provide an adequate fact-based analysis…[to] allow for an objective assessment” to determine if additional environmental protection measures are needed. In particular, the MSC criticized the proposed new “prescriptive” requirements for impoundments storing freshwater (section 78.59b), characterizing them as “arbitrary and capricious” since no other industry in Pennsylvania is subject to similar rules.

On the other hand, the MSC supports the proposed requirement to identify abandoned and orphaned wells prior to hydraulic fracturing (section 78.52a) and also the proposal to facilitate the maximum reuse of produced water (section 78.58).

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Secretary of Interior testifies that hydraulic fracturing regulations will be finalized by end of 2014

On March 25, 2014, the U.S. Department Secretary of the Interior Sally Jewell testified before the House Appropriations Subcommittee concerning the budget for the DOI and responded to questions relating to the proposed regulations concerning hydraulic fracturing on federal lands. Ms. Jewell testified that the DOI is currently reviewing the more than 1.3 million comments received from the public after the introduction of the revised regulations in May 2013. She anticipates that the Bureau of Land Management will finalize the rules before the end of 2014.

Telling the representatives that the proposed regulations will continue to evolve, Ms. Jewell stated that “I’ve fracked wells before and I’ve been in the industry. I know that technology moves on and we have to keep up and apply the best available sciences.” Along with the best available science, the rules will incorporate lessons learned from states that have been regulating fracking for a number of years.

Ms. Jewell mentioned that the U.S. Geological Survey would be continuing studies into induced seismicity and wellbore integrity, both important issues to be considered and incorporated into the regulations being proposed.

For additional information on the proposed hydraulic fracturing regulations, click here.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Barnett Shale gas operators encounter opposition to hydraulic fracturing

Environmental groups, anti-fracking activists, and many urban residents want to tighten oil and gas regulations in the Barnett Shale in North Texas. Cities in the area are passing or considering legislation to limit where new wells can be drilled or to ban hydraulic fracturing completely. Recent occurrences have been:

  • On October 18, 2013, the city of Denton, Texas filed suit against Eagleridge Energy LLC to prevent the company from continuing to drill two new gas wells in an area between two residential developments without the required city permit approvals. The city argued that Eagleridge was violating ordinances that require approval of a site plan before drilling can commence and a setback of 1,200 feet from any residence. City of Denton v. Eagleridge Energy LLC, et al., Case No. 2013-30817-211, In the 211th Judicial District Court of Denton County, Texas.
  • On December 11, 2013, the Dallas City Council approved regulations that require gas wells to be at least 1,500 feet from homes, schools, churches and other protected properties. The regulations contain provisions concerning neighborhood meeting requirements, baseline sampling and testing of air, soil , noise and water, limitations on hours of operation, spill prevention and tracking, site maintenance, emissions, and materials management. 
  • On February 13, 2014, Trinity East Energy LLC sued the city of Dallas for alleged breach of an oil and gas lease when the City Council voted to deny the company’s drilling permits on public land. Seeking more than $200 million in damages, Trinity East argues that the city’s planning commission denied the permits without any evidence that the drilling would cause harm to the environment or to the residents. A spokesperson for Dallas stated that Trinity had asked for permits to drill on city park land, in the floodplain and near a new soccer complex and that the city validly exercised its regulatory powers to protect public health and safety as well as the environment by denying the permits. Trinity East Energy LLC v. Dallas, Case No. DC-14-01443, In the 192nd Judicial District Court of Dallas County, Texas.
  • The anti-fracking group Denton Drilling Awareness Group started a signature campaign in February to allow the city residents to vote on a ban of hydraulic fracturing in the November elections. The group wants more protections incorporated into the city’s oil and gas ordinances, including prohibitions on open pits, compressor stations, and flaring as well as required notification to area residents of the presence of near-by wells and the possibility of hydraulic fracturing taking place.

This post was written by Barclay Nicholson ( 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.

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.
For a presentation made by the North Dakota Industrial Commission concerning these recommendations, click here.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Shale Gas Projects are absent in EU’s updated EIA

On March 12, 2014, the European Parliament (EU) supported a proposed update to make environmental impact assessments (EIAs) clearer, to ensure that EIAs take into account biodiversity and climate change, and to involve the public via a central web portal.

Approximately 200 types of projects are covered in the directive, including bridges, ports, roadways, and landfill sites.

Shale gas projects, including hydraulic fracturing, were not included in the legislation.

However, according to the EU’s press release, “new aspects of gas projects will have to be taken into account, notably the risks to human health due to water contamination, use of soil and water as well as the quality and regenerative capacity of water underground. If member states conclude that no assessment is needed, then they will have to state the reasons why.”

The fact that shale gas development is not referenced in the updated directive is seen as indicating that the EU is concerned with energy security.

The EU wants its member countries to become self-sufficient for their energy needs and not rely on other countries, especially Russia, to supply their oil and gas.

This is particularly true in light of the geopolitical unrest in the Ukraine. Approximately 16 percent of Europe’s natural gas flows through the Ukraine.

The updated EIA directive provides flexibility for the divergent views among the member countries about shale gas exploration, which views include France banning hydraulic fracturing and the UK and Poland actively seeking development of their shale gas resources.

Wyoming Supreme Court reverses & remands suit on trade secret protection for hydraulic fracturing chemicals

Four environmental groups sued the Wyoming Oil and Gas Conservation Commission (WOGCC) under Wyoming’s Administrative Procedure Act (APA), asserting that the WOGCC unlawfully withheld the identification of hydraulic fracturing chemicals used by various oil and gas operators under the trade secret exception to the state’s disclosure rules.

On March 21, 2013, the district court upheld the WOGCC’s decision, ruling that the Supervisor “acted reasonably” in establishing a policy for evaluating trade secret requests and that his decisions to grant trade secret protection were not arbitrary or capricious and were in accordance with the law.

On March 12, 2014, the Wyoming Supreme Court reversed and remanded the lawsuit for further proceedings, pointing to a “procedural flaw” and stating that “[b]ecause the district court reviewed the Commission Supervisor’s decision under the APA, we must reverse and remand.”

The Supreme Court found that, in their prayer for relief, the environmental groups “asked the district court to compel the Supervisor to show cause why its partial denial of their request for access to its records was lawful.

However, no order to show cause [under the Wyoming Public Records Act (WPRA)] was ever issued, and…the district court never held a show-cause evidentiary hearing.”

The Supreme Court directed the district court to determine whether it will allow the environmental groups “to amend their existing pleadings to request and issue an order to the Supervisor to show cause as to why the documents requested should not be produced, or dismiss the case, which will permit Appellants to file a new action.”

“[U]nwilling to cast the district court adrift without some guidance on the standard to be applied…” and adopting the Freedom of Information Act standard, the Supreme Court defined a trade secret under the WPRA as “a secret, commercially valuable plan, formula, process, or device that is used for the making, preparing, compounding, or processing of trade commodities and that can be said to be the end product of either innovation or substantial effort, with a direct relationship between the trade secret and the productive process.”

The district court is required to determine as a matter of fact based on evidence presented to it whether the information sought is a trade secret.

The district court will have to “review the disputed information on a case-by-case, record-by-record, or perhaps even on an operator-by-operator basis, applying the definition of trade secrets…and making the particularized findings which independently explain the basis of its ruling for each.”

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Pennsylvania House Committee Tables Bill Establishing Royalty Minimums

On March 11, 2014, Pennsylvania House Bill 1684, which would have established fixed minimum royalty payments for landowners with unconventional gas leases, was tabled in the Pennsylvania House of Representatives.

The House Environmental Resources and Energy Committee was apparently unable to move the bill to a vote due to inconsistency in the wording of the bill. 

Specifically, the bill stated that gas companies could not lower royalties below a certain threshold by deducting “production costs,” rather than “post-production costs.” 

Garth Everett, R-Lycoming, the bill’s sponsor, made a verbal motion to change the language before the bill was tabled.

H.B. 1684 provides that a lease cannot allow any deductions for:
severance or other production taxes or costs associated with producing, gathering, storing, separating, treating, dehydrating, compressing, processing, transporting, marketing or other marketing enhancements to be deducted from any royalty payable to a lessor if such deductions result in a royalty of less than one-eighth calculated under the first marketable product doctrine.
H.B. 1684 is an amendment to Pennsylvania’s Guaranteed Minimum Royalty Act (“GMRA”), which currently requires leaseholders to receive at least 12.5 percent of the value of gas extracted from their land.

The current GMRA does not specify the point at which such royalty is to be calculated, however, so the value of extracted gas may be calculated at the wellhead, at the time the gas has been sold to a third party, or at some point during the process to render the gas marketable. See Kilmer v. Elexco Land Services, Inc., et al., 990 A.2d 1147 (Pa. 2010) (holding that GMRA permits “the calculation of royalties at the wellhead, as provided by the net-back method in the Lease,” which states that “lessor shall receive as its royalty one-eighth (1/8th) of the sales proceeds actually received from the sale of such production, less this same percentage share of all Post Production Costs”).

The bill was originally introduced on September 16, 2013, as part of a package of three bills addressing the deduction of post-production costs and pooling of mineral leases. 

Three additional bills, aimed at giving leaseholders greater transparency into how royalty payments are calculated, were subsequently introduced on September 30, 2013. 

None of the bills has yet to move out of committee.

See prior blog postings

This article was prepared by Lauren Brogdon ( or 713 651 5375) from Norton Rose Fulbright’s Energy Practice Group.

Court Upholds Broomfield, Colorado’s Ban on Hydraulic Fracturing

After a re-count of the votes cast on November 5, 2013, in Broomfield, Colorado, Local Question 300 banning hydraulic fracturing within the city for five years was passed by 20 votes.

The Broomfield Balanced Energy Coalition and others challenged the legality of the local moratorium by questioning the validity of the election results. 

The groups pointed to a recent “bad election bill” concerning state residency requirements for voters in coordinated elections, a “deceptively written” Local Question 300, and “incompetent” election officials in Broomfield who admitted to mistakes including the discovery of a ballot box four months after the election.

In a detailed Order dated February 27, 2014, the Judge for the District Court for the City and County of Broomfield reviewed the groups’ allegations and ruled to uphold the election results, stating that the city “substantially complied with the election laws of the State of Colorado and that the election should not be set aside.” 

The lawsuit is Thomas E. Cave and Broomfield Balanced Energy Coalition v. The City and County of Broomfield, Colorado, et al., Case No. 13CV30313, In the District Court, City and County of Broomfield, State of Colorado.

A number of lawsuits have been filed challenging local bans or moratoria on hydraulic fracturing. 

For information on these lawsuits, please read the Norton Rose Fulbright white paper entitled “Analysis of Litigation Involving Shale & Hydraulic Fracturing”.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Brighton, Colorado Suspends Oil and Gas Drilling Applications for 4 Months

On March 4, 2014, the City Council of Brighton, Colorado unanimously voted to suspend all oil and gas drilling applications for the next four months, through July 15, 2014.

City officials explained that this is not intended as a ban on drilling operations, but merely a temporary suspension to give the Council more time to update the oil and gas regulations in the city code. 

The delay will give provide time to draft and revise ordinances that address local concerns and assure consistency with state regulations, to consult with the Colorado Oil and Gas Conservation Commission (COGCC) and the Colorado Oil and Gas Association (COGA), and to educate the Council and members of the city’s planning and zoning commission on oil and gas drilling and the new regulations. 

One of the Council members stressed that, unlike most Colorado cities, the water for Brighton comes from shallow wells and additional time is needed to address this unique concern in the regulations.

Before the vote by the City Council, members heard testimony from representatives of the oil and gas industry, Brighton residents who work for oil and gas companies, and the state Attorney General’s office, all of whom stating that the moratorium was unnecessary and sent the wrong message to energy companies. 

A COGA representative urged the members to use the existing state permitting and local government designee process to address local concerns while revising the regulations. 

The assistant attorney with the Attorney General’s Office encouraged the Council to vote down the moratorium because it was inappropriate, pointing out that currently there are no permits pending before the COGCC, that state rules apply regardless if cities have the same rules, and that the city could demand a COGCC hearing if a permit application were to be filed.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

EPA proposes revisions to greenhouse gas reporting rules for petroleum and natural gas systems

The U.S. Environmental Protection Agency (EPA) has proposed revisions to its greenhouse gas reporting rules for the oil and gas industry. Published in the March 10, 2014 edition of the Federal Register, the proposal addresses the petroleum and natural gas systems source category (40 CFR 98, Subpart W) and the general provisions (40 CFR 98, Subpart A).

The proposed changes include revisions to “certain calculation methods, monitoring and data reporting requirements, terms and definitions, and technical and editorial errors…” as well as proposing “confidentiality determinations for new or substantially revised data elements” in the rules.

The revised reporting rule eliminates the Best Available Monitoring Method (BAMM) provision which currently allows the use of alternative engineering calculations or supplier data to determine greenhouse gas emissions.

According to the EPA, the “proposed revisions to calculation methods would provide greater flexibility and potentially reduce burden to facilities,…and increase clarity and congruency of calculation and reporting requirements…” by increasing options for calculation of emissions from various sources, such as compressors, natural gas pneumatic device venting, acid gas removal vents, dehydrators, liquids unloading, gas well completions, workovers, venting and flaring, storage tanks, and natural gas distribution sources.

Separate reporting of emissions of each of the six key greenhouse gases (carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride) in metric tons would be required – rather than simply reporting the total carbon dioxide-equivalent emissions.

These proposed revisions are open for public comment until April 24, 2014. If finalized, these revisions would become effective on January 1, 2015.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Council of the District of Columbia votes to prohibit fracking in the George Washington National Forest

At the Washington, DC City Council meeting on March 6, 2014, all twelve lawmakers present unanimously voted to prohibit horizontal hydraulic fracturing operations in the nearby George Washington National Forest.

The 1.1 million-acre forest located in Virginia and West Virginia, with more than half lying over the Marcellus Shale geological formation, contains the headwaters of the Potomac River, which is the sole source of drinking water for the nation’s capital.

The Council’s resolution states horizontal hydraulic fracturing “has been linked to significant adverse environmental impacts, including surface and drinking water contamination.”

Citing to letters from local water officials with the Washington Aqueduct and DC Water and to comments from other near-by cities and counties expressing opposition to fracking operations in the forest, the Council resolved that “the United States Forest Service should prohibit horizontal hydraulic fracturing in the George Washington National Forest in its upcoming Revised Land and Resource Management Plan to protect water quality and supply in the Potomac River watershed.”

The Council expressed concern that any changes in source water quality would increase costs for the local citizens since the water would require additional treatment, monitoring and compliance.

The U.S. Forest Service’s revised management plan is to cover the next 10 to 15 years, and that plan may include hydraulic fracturing in the George Washington National Park.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

U.S. Department of Energy Task Force Report recommends that companies fully disclose all known constituents of fracking fluids

On March 5, 2014, the U.S. Department of Energy released a Task Force Report on FracFocus 2.0 concerning the website’s operating procedures, the timeliness, completeness and accuracy of the data, the extent to which information is withheld as being proprietary, data handling and retention practices, usefulness to regulatory officials and the public, the potential to include well-water quality data collected pre-stimulation and post-production and the adequacy of the existing data collection mechanism.

Composed of representatives from industry, environmental groups and academia, the Task Force found that, while FracFocus has provided increased knowledge of hydraulic fracturing operations, additional information must still be disclosed to lessen the public’s concerns about the chemicals being used.

FracFocus is a nationwide database in which companies voluntarily disclose information about their hydraulic fracturing activities, including the composition of the fluids being used with an exception for trade secrets. The Task Force found that about 84% of the wells reporting to FracFocus include at least one trade secret exception. “On average, trade secret exemptions were claimed for 16% of the chemical entries recorded in the FracFocus database between June and December 2013.”

The Task Force recommends “full disclosure of all known constituents added to fracturing fluid with few, if any exemptions. A ‘systems approach’ that reports the chemicals added separately from the additive names and product names that contain them, generally should provide adequate protection of trade secrets. The Task Force further calls for state and federal regulators [including the Bureau of Land Management] to adopt standards for making a trade secret claim and establish an accompanying compliance process and a challenge mechanism.”

The Task Force’s full disclosure recommendation requires operators (1) not to make trade secret disclaimers unless documented and attested as is done in Wyoming or Arkansas, (2) to report the complete list of chemicals by their CAS numbers and quantities added, and (3) to provide a complete list of products without linking to the list of chemicals. “The Task Force believes that if the leading operators and oil field service companies establish practical protocols for data transfer across the supply chain, and clear requirements for their suppliers, then supplier insistence of trade secrets will be greatly reduced and possibly disappear.”

In addition to suggestions for technical improvements to the website, such as searching by fields, expanding the 2000-record display, and allowing batch downloads, the Task Force suggests that the DOE provide stable funding for FracFocus and that oil and gas companies pay a registration fee of $50 per well.

Some critics object to the recommended full chemical disclosure, stating that this would be like disclosing the formula for Coca-Cola, and the registration fee, indicating that both would discourage oil and gas companies from voluntarily providing any information to FracFocus

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Michigan Court of Appeals holds that a well completed using hydraulic fracturing is not an injection well

Several Michigan citizens and the group Ban Michigan Fracking questioned the Department of Environmental Quality (DEQ) about its definition of “injection well” in Mich. Admin. Code , R. 324.102(x), urging that the definition should include wells completed with hydraulic fracturing (“frack wells”).

The DEQ responded by stating that “a frack well is not an injection well under Rule 324.102(x) because a frack well injects fluids for the ‘initial stimulation’ of oil and gas, whereas Rule 324.102(x) limits injection wells to wells that are used for disposal, storage, or secondary recovery of oil and gas.”

The citizens and Ban Michigan Fracking then filed a declaratory judgment action, requesting that the definition of injection well include a frack well, thus making the regulations relating to injection wells applicable to frack wells.

On February 11, 2014, the Michigan Court of Appeals sided with the DEQ, stating that under the plain language of the rule, an “injection well is either a well used to dispose of…waste fluids or a well used to inject…fluids for the purpose of increasing the ultimate recovery of hydrocarbons from a reservoir or for the storage of hydrocarbons.”

According to the court, for a well to be categorized as an “injection well,” it must be used for the purposes of recovering hydrocarbons before and after the injection of fluid.

The court continued:
“…it is undisputed that the frack wells at issue are not used for the purpose of recovering hydrocarbons before the injection of fluid… [B]ecause a newly constructed frack well does not involve the continuing recovery of hydrocarbons, but rather the initial recovery of hydrocarbons when such recovery was nonexistent, the wells at issue here to not fall within the scope of the unambiguous language of Rule 324.102(x).

On March 3, 2014, a motion for reconsideration was filed, asking the court to resolve a separate part of the appeal which the opinion overlooked.  The appellants indicate that the court’s opinion did not adjudicate the “contention that a frack well is used to dispose of waste fluids.”

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

EIA’s overview indicates that hydraulic fracturing and horizontal drilling are driving forces in current oil and natural gas production

The U.S. Energy Information Administration issued a 20-page overview of its Annual Energy Outlook 2014. The final report which analyzes US energy supply, demand and prices through 2040 will be released in spring 2014. The report confirms that hydraulic fracturing and horizontal drilling are driving the current oil and natural gas boom.

It is anticipated that there will be a spike of 800,000 barrels a day in domestic crude oil production in 2014. By 2016, crude oil production will increase to nearly the 9.6 million barrels per day achieved in 1970. “While domestic crude oil production is expected to level off and then slowly decline after 2020…, natural gas production grows steadily with a 56% increase between 2012 and 2040, when production reaches 37.6 trillion cubic feet (Tcf).”

Additional key findings in the overview include:
  • Low natural gas prices are projected to continue due to increased production.
  • By 2040, natural gas will overtake coal to provide the largest share of US electric power generation.
  • With the strong growth in domestic crude oil and natural gas production, US reliance on imported fuels will fall sharply between 2014 and 2040.
  • Improved efficiency of energy use in the residential and transportation sectors and a shift away from carbon-intensive fuels for electricity generation keep US energy-related carbon dioxide emissions below their 2005 level through 2040.
  • The pace of oil-directed drilling in the near term is much stronger than in the 2013 outlook, as producers locate and target the sweet spots of plays currently under development and find additional tight formations that can be developed with the latest technologies.
  • Cumulative production of dry natural gas from 2012 to 2040 is about 11% higher than in 2013, primarily reflecting continued growth in shale gas production resulting from hydraulic fracturing and horizontal drilling. Another contributing factor is ongoing drilling in shale and other plays with high concentrations of NGL and crude oil, which in energy-equivalent terms have a higher value than dry natural gas.
  • The US becomes a net exporter of LNG in 2016.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Kansas Governor creates panel to study possible connection between recent earthquakes and oil and gas activities

Governor Sam Brownback has created a 3-person task force to study whether oil and gas activities such as hydraulic fracturing are connected to the increased number of minor earthquakes occurring in south central Kansas, near the Kansas-Oklahoma border. The Kansas Geological Survey has recorded more than 24 minor earthquakes in the past two years. Two earthquakes were recently measured in that area – one on December 16, 2013 and a second on February 3, 2014, with magnitudes of 3.8 and 3.9 respectively. No damage was reported from these earthquakes, with one county official noting that “no cows tipped over.” According to the U.S. Geological Survey, “it is very unusual” to have two earthquakes in the same area in such a short period of time.

Don Blakeman who is a geophysicist with the National Earthquake Information Center in Golden, Colorado, and other scientists have stated that it is difficult to attribute an earthquake to a specific cause. Identifying the cause takes “more study, typically more instruments on the ground and collaboration with companies to know when they are re-injecting fluids” and performing other operations. Currently there are only two monitoring stations in Kansas, and this will hamper analysis.

The panel which will hold its first public meeting on April 16, 2014, at the Wichita State University’s Hughes Metropolitan Complex is made up of Rex Buchanan, interim director of the Kansas Geological Survey; Kim Christiansen, executive director of the Kansas Corporation Commission; and Mike Tate, chief of the Bureau of Water at the Kansas Department of Health and Environment.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Colorado's air quality control commission approves hydrocarbon emission control requirements

After a five-day public hearing, on Sunday February 23, 2014, the Colorado Air Quality Control Commission in an 8 to 1 vote approved regulations to control hydrocarbon emissions of volatile organic compounds (VOCs). The Commission estimates that these rules which include input from the Environmental Defense Fund and a number of oil and gas companies, including Anadarko Petroleum Corporation, Noble Energy Inc., and Encana Corporation, will reduce methane emissions by an estimated 92,000 tons per year in the state.

These regulations for oil and gas operations include:
  • Storage Tanks – Beginning May 1, 2014, owners or operators of storage tanks at well production facilities must collect and control emissions by routing emissions to operating air pollution control equipment during the first 90 days after the date of first production. The air pollution control equipment must achieve an average hydrocarbon control efficiency of 95%.
  • Inspections of Storage Tanks – Beginning May 1, 2014, owners or operators of storage tanks must conduct audio, visual, olfactory and additional visual inspections of the storage tanks and any associated equipment at least once every 31 days.
  • Storage Tank Emission Management System (“STEM”) must be developed. All hydrocarbon emissions must be routed to air pollution control equipment and must be operate without venting hydrocarbon emissions from the thief hatch or pressure relief device during normal operation, unless venting is reasonably required for maintenance or safety of personnel and equipment.
  • Glycol Natural Gas Dehydrators – Beginning May 1, 2015, still vents and vents from any flash separator or flash tank on a glycol natural gas dehydrator located at an oil and gas exploration and production operation, natural gas compressor station, or gas-processing plant must reduce uncontrolled actual emissions of hydrocarbons by at least 95% on a rolling 12-month basis through the use of a condenser or air pollution control equipment.
  • Leak Detection and Repair (“LDAR”) Programs for well production facilities and natural gas compressor stations must be conducted
  • Repair and Remonitoring – Repairs for a leak must be made no later than 5 working days after discovery unless parts are unavailable, the equipment requires shutdown to complete the repair or other good cause exists. Within 15 days of the repair, the leak must be remonitored to verify that the repair was effective.
  • Venting During Downhole Well Maintenance – Beginning May 1, 2014, owners or operators must use best management practices to minimize hydrocarbon emissions and the need for well venting associated with downhole well maintenance and liquids unloading, unless venting is necessary for safety.
With these regulations, Colorado becomes the first state to directly regulate methane emissions from oil and gas operations. The U.S. Environmental Protection Agency in April 2012 proposed new source performance standards under the Clean Air Act and national emission standards for hazardous air pollutants. These standards require companies to use “green completions” to capture and treat hydrocarbons by January 2015, as opposed to using flaring or burning off the emissions. The EPA estimates that with full implementation of these standards methane emissions will be reduced by up to 1.7 million tons annually.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Environmental groups seek to intervene to defend Fort Collins' moratorium on hydraulic fracturing

On February 13, 2014, Citizens for a Healthy Fort Collins, the Sierra Club, and Earthworks filed a motion to intervene in Colorado Oil and Gas Association v. City of Fort Collins, Colorado, Case No. 2013CV031385, In the District Court, Larimer County, Colorado (December 3, 2013), a lawsuit challenging the city of Fort Collins authority to ban hydraulic fracturing.

In November 2013, the 55% of the citizens of Fort Collins, Colorado voted to ban hydraulic fracturing from their city for five years. On December 3, 2013, the Colorado Oil & Gas Association filed a lawsuit against the city, arguing that the city has no constitutional or statutory authority to implement regulations on oil and gas development techniques, such as hydraulic fracturing. The environmental groups represented by the University of Denver Environmental Law Clinic want to intervene to uphold the fracking ban, stating that the city cannot adequately represent their interests because the city council opposed the ban during the election and is now concerned about the cost of defending the lawsuit.

Citizens for a Healthy Fort Collins see the lawsuit as a “blatant attempt…to bypass the will of the voters and possibly jeopardize public health, safety and property values in our community.” A representative from the law clinic urged that “there is no good reason not to wait and see the results of ongoing health and safety studies before the City decides whether or not to allow this industrial practice into its residents’ backyards.”

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.

Study indicates that methane emissions may exceed EPA estimates

A study conducted by a Stanford University associate professor of energy resources engineering and other scientists evaluated more than 200 scientific papers relating to methane emissions in the United States and Canada. The results of the study entitled “Methane Leakage from North American Natural Gas Systems” are published in the February 14th edition of the journal Science.

According to the scientists, organizations such as the U.S. Environmental Protection Agency have underestimated methane emissions generally as well as those from the natural gas industry specifically. “Atmospheric tests covering the entire country indicate around 50% more than EPA estimates.” The study shows that a significant portion of the methane comes from leakage at conventional well sites, processing plants, storage tanks, and pipelines or other distribution centers. The scientists also found that there was no increase in methane leakage due to hydraulic fracturing.

This study concludes that the natural gas industry must maintain its equipment in order to avoid all unintentional leaks. “Reducing easily avoidable methane leaks from the natural gas system is important for domestic energy security,” according to Robert Harriss, a methane researcher at the Environmental Defense Fund and a co-author of the study.

It should be noted that a September 2013 study by the University of Texas published in the Proceedings of the National Academy of Sciences entitled “Measurements of methane emissions at natural gas production sites in the United States” found that well completion emissions were lower than previously estimated by the EPA and that estimates of total emissions were similar to the EPA’s estimates. These conclusions were reached after taking direct measurements of methane emissions at 190 onshore natural gas sites in the US.

This post was written by Barclay Nicholson ( or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.