Hydraulic Fracking Blog: March 2015

Alberta Energy Regulator responds to earthquakes possibly linked to fracking

The Alberta Energy Regulator (AER) has issued new rules which create a "traffic light" process in response to earthquakes believed to have been caused by hydraulic fracturing. Subsurface Order No. 2 comes after several seismic events that may be related to hydraulic fracturing were recorded in the Duvernay play near Fox Creek in northwestern Alberta. A 3.8 magnitude earthquake measured on the Richter scale happened on January 214, 2015 and a 4.4 magnitude earthquake was recorded on January 22, 2014. Both were felt by residents of Fox Creek but there were no injuries or damage.

Some researchers believe that these and other recent shallow earthquakes in the area are consistent with being induced by hydraulic fracturing operations although it is impossible to definitely state that they were not naturally occurring earthquakes. The Fox Creek area historically has not had a lot of seismicity until hydraulic fracturing operations started in 2013. Since then, researches have recorded hundreds of very minor earthquakes and aftershocks at depths much shallower than where natural earthquakes typically occur. The Alberta Geological Survey, a part of the AER, regularly monitors seismic activity throughout Alberta through the 53-station Regional Alberta Observatory for Earthquake Studies Network (RAVEN).

Subsurface Order No. 2 requires that effective immediately that every well licensee of a well with a surface or bottom hole located in the Duvernay zone at which any completion operations are contemplated that include hydraulic fracturing must:

before beginning any completion operations that include hydraulic fracturing, assess the potential for induced seismicity and establish and implement a plan to monitor for, mitigate and respond to any induced seismicity that may occur or result from its completion operations;
the monitoring must be capable of detecting a 2.0 local magnitude seismic event within 5 kilometres (3.1 miles) of the well;
the licensee must immediately report to the AER all seismic events recorded of 2.0 or greater within 5 kilometres of the well and implement their induced seismicity plan in a manner that eliminates or reduces further seismic events;
if a 4.0 or greater seismic event is recorded within 5 km of the well, the licensee must immediately stop hydraulic fracturing operations at the well and return the well to a safe state; and
hydraulic fracturing of a well which have been suspended may only be recommenced with the AER's written consent.

Review a copy of Subsurface Order No. 2.

This post was written by Alan Harvie (alan.harvie@nortonrosefulbright.com or +1 403.267.9411) from Norton Rose Fulbright's energy practice group.

Bureau of Land Management releases new federal regulations for hydraulic fracturing

In 2012, the Department of the Interior’s Bureau of Land Management (BLM) circulated a proposed rule governing the use of hydraulic fracturing on federal land. That proposal garnered a significant amount of interest and public comment. Today, the BLM released a final version of those regulations aimed specifically at hydraulic fracturing. The BLM has been working on these regulations since President Obama’s first term.

Under the new regulations, operators are required to conduct a mechanical integrity test before engaging in hydraulic fracturing operations. Moreover, if an operator encounters cementing problems with a well, the operator is required to show the BLM that the problem has been remedied. Operators are also required to monitor annulus pressure while hydraulic fracturing operations are ongoing. In addition, any fluids recovered during fracking operations must be contained in an above-ground storage tank. The rules contains a few limited exceptions; however, the exceptions have to be approved on a case-by-case basis. Additionally, the new regulations require all wells to satisfy best practices standards. The regulations authorize government employees to inspect the cement barriers of wells.

The new regulations also heighten reporting requirements. Oil and gas companies will be required to disclose the chemical composition of their fracking fluids. Companies must make this disclosure within thirty days of finishing a particular drilling operation. The new rules make an exception for information qualifying as a trade secret; however, companies must submit an affidavit to prove trade secret status. Companies are still permitted to use FracFocus to make their disclosures. The BLM noted that it is negotiating a memorandum of understanding (MOU) with the Ground Water Protection Council (GWPC), the organization that manages FracFocus. Under the MOU, the GWPC will notify the BLM each time chemical disclosures are uploaded on the site. The rules require companies with operations on federal land to follow state and federal disclosure requirements; however, if the state regulation is stricter, the state can request a variance that requires operators to comply with the stricter state rule. Companies will also have to submit additional information to the BLM concerning wellbore geology, fault and fracture locations, water depths, the volume of fluids used, and the direction and length of fractures.

According to the BLM, the new regulations are necessary because of the dramatic growth in hydraulic fracturing operations throughout the country. The BLM has indicated that it believes the new rules will ensure that wells are constructed in a manner that will protect water supplies and that fluids involved in hydraulic fracturing operations are utilized so as to avoid any negative impact on the environment. In addition, the BLM has expressed a desire that the new regulations improve public disclosure of the chemicals used in hydraulic fracturing and increase the cohesion between federal and state standards.

The new rules are set to take effect in ninety days after it is published in the Federal Register. The impact of the rule is debatable as the new regulations only apply to oil and gas wells on public lands, and the majority of fracking is conducted on private property. That said, commentators have suggested that these new regulations will further stymie the growth of hydraulic fracturing on public lands. In fact, the BLM estimated that it will cost operators $11,400 per well to comply with the new regulations. The Independent Petroleum Association of America and Western Energy Alliance have already filed suit to challenge the regulations.

Read the new regulations.

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.

Texas Legislature considers incentives for use of alternative fracking fluids

The Texas Legislature is currently considering several bills related to hydraulic fracturing and the oil and gas industry in general. Last Friday, March 13th, two additional bills were proposed in the Texas Legislature that would incentivize the use of alternative fracking fluids. The bills—H.B. 4035 and H.B. 4021—were introduced by Representative Drew Darby and Representative Abel Herrero, respectively.

H.B. 4035 proposes to establish a tax credit for oil and gas operators that use a “no water production technique” in their drilling operations. An operator utilizes a “no water production technique” if the operator “uses nitrogen, carbon dioxide, or fluids other than water.” In addition, H.B. 4035 would grant a tax credit if oil and gas operators contribute to water infrastructure and road projects in Texas. The amount of the tax credit cannot exceed $10,000.

Similarly, H.B. 4021 would grant oil and gas operators a $50,000 tax credit for each well that is operated without the use of fresh water. Under H.B. 4021, the Railroad Commission of Texas (RRC) would be responsible for maintaining a database to ensure that operators actually qualify for the tax credit. In fact, the RRC would be required to send a list to the Texas Comptroller of Public Accounts (Comptroller) of all of the well operators who qualify for the tax credit. Operators desiring to claim the tax credit would then be required to apply to the Comptroller for the credit. H.B. 4021 also authorizes the RRC to conduct random inspections to verify the information submitted by well operators.

These bills likely stem from drought concerns expressed by many parties in Texas. Several studies have concluded that certain areas in the state are experiencing a dwindling supply of groundwater.

Read H.B. 4035 and H.B. 4021.

Texas legislature considers bills to restrict local regulation of oil and gas activities

Soon after Denton, Texas enacted its hydraulic fracturing ban, many commentators suggested that the Texas Legislature may enact legislation targeted at restricting the ability of local governments to adopt anti-fracking measures. It appears that this prediction was accurate. On March 13th, members of the Texas Legislature introduced two bills aimed at limiting the authority of local governments with respect to oil and gas regulation.

One of the bills—S.B. 1806— proposes to invalidate any local ordinance that conflicts with state law. The other bill—S.B. 1673—also proposes to nullify any local measure that conflicts with state law. In addition, S.B. 1673 would prohibit localities from enacting legislation that imposes stricter regulations than required under state law. S.B. 1673 would strip localities of governmental immunity to suit for violations of the bill. S.B. 1806 was introduced by Senator Craig Estes, and S.B. 1673 was sponsored by Senator Don Huffines.

The Texas Legislature is also weighing other bills proposed in response to the Denton fracking ban. For example, H.B. 540 would prohibit localities from placing measures on local ballots until those measures have been approved as legal. Representative Phil King, the sponsor of H.B. 540, has stated that the purpose of the bill is to protect taxpayers from having to pay for the inevitable legal challenges that arise from anti-fracking measures similar to Denton’s ban. Additionally, King has introduced H.B. 539 that would mandate that localities inform local voters of the financial cost associated with introducing anti-fracking measures.

Representative Drew Darby has also sponsored legislation aimed at restricting local regulation of the oil and gas industry. Representative Darby’s bill—H.B. 40—would prohibit localities from enacting legislation purporting to regulate the oil and gas operations. The bill would also restrict local governance of setback rules.

Read S.B. 1806 and S.B. 1673.

Ohio court strikes down local drilling ban

On March 10, 2015, a Cuyahoga County trial court struck down a local ban on oil and gas development. See Bass Energy, Inc. v. Broadview Heights, Slip Opinion No. CV-14-828074 (Cuyahoga Cnty. Ct. Mar. 10, 2015). This decision comes less than a month after the Ohio Supreme Court struck down a neighboring city’s ordinance which restricted oil and gas development. See State ex rel. Morrison v. Beck Energy Corp, Slip Opinion No. 2015-Ohio-485 (Feb. 17, 2015). Review Norton Rose Fulbright’s previous discussion of the Morrison decision.

On November 06, 2012, voters in Broadview Heights, a suburb of Akron, amended the city’s charter to include a “Community Bill of Rights” (the “Amendment”) that prohibited any future oil and gas drilling within the city. An exploration and production company obtained a drilling permit from the Ohio Department of Natural Resources (ODNR) for a well within the city but was told that the city would enforce the Amendment. Therefore, the exploration and production company challenged the city’s ban, arguing that the Amendment was preempted by Ohio Revised Code Chapter 1509, which, among other things, established the ODNR as the “sole and exclusive authority” to regulate the permitting, locating, and spacing of oil and gas wells in Ohio. Judge Michael Astrab agreed, writing “reasonable minds could come to only one conclusion: [the Amendment] is preempted by [Chapter 1509].”

The court’s decision closely tracked the Ohio Supreme Court’s opinion in Morrison. Under Ohio law, a municipal ordinance is preempted by a state statute if:

the ordinance is an exercise of police power, rather than of local self-government;
the statute is a general law; and
the ordinance is in conflict with the statute.

Judge Astrab determined that all three elements were satisfied and, therefore, the Amendment was preempted. First, the Amendment clearly was an exercise of police power because the city was trying to protect the “public health” and “general welfare of the public.” Second, the Ohio Supreme Court explicitly found that Chapter 1509 was a general law. Finally, the Amendment directly conflicted with Chapter 1509 because it prohibited an activity permitted by the State. Thus, the court declared the Amendment unenforceable.

This post was written by Joshua Snyder (joshua.snyder@nortonrosefulbright.com or +1 724 416 0432), Jeremy Mercer (jeremy.mercer@nortonrosefulbright.com or +1 724 416 0440) and Michael Gaetani (michael.gaetani@nortonrosefulbright.com or +1 724 416 0429) from Norton Rose Fulbright's Energy Practice Group.

California Governor asked to impose fracking moratorium

Thus far, California has rebuffed attempts at instituting a statewide ban on hydraulic fracturing. In fact, several localities in California have also rejected fracking bans. Nonetheless, on Thursday, several environmental groups petitioned California Governor Edmund G. Brown to impose an immediate moratorium on hydraulic fracturing and other methods of well stimulation in the state.

The petitioners claimed that such an action was necessary to protect the public from an imminent threat to its health and safety. According to the petitioners, fracking causes pollution, contaminates aquifers, relies on harmful chemicals, and increases the likelihood of earthquakes. The petitioners also blame hydraulic fracturing for climate change. In fact, the petitioners attempt to blame fracking for several illnesses suffered by California residents.

Petitioners claim that their petition is supported by several scientific studies. These studies, Petitioners allege, demonstrate that fracking is dangerous. In addition, petitioners point to the fracking ban enacted by New York Governor Andrew Cuomo after the state conducted a study of the alleged harm caused by hydraulic fracturing.

The petitioners take issue with the environmental studies conducted by California and the state’s current regulations. They contend that California should have completed its study by now. Moreover, the petitioners argue that the latest report released by the state is insufficient and flawed. The petitioners also claim that the state’s current regulations for wastewater disposal are unlawful and fail to properly protect California residents.

Read the petition.

Middle District of Pennsylvania finds separate natural gas compressor stations are not a “single source”

On February 23, 2015, the US District Court for the Middle District of Pennsylvania granted Ultra Resources, Inc.’s motion for summary judgment, holding as a matter of law that eight compressor stations owned and operated by Ultra Resources, Inc. (“Ultra”) were not a “single source” for air quality permitting purposes. See Citizens for Pennsylvania's Future v. Ultra Res., Inc., No. 4:11CV01360, 2015 US Dist. LEXIS 21357 (M.D. Pa. Feb. 23, 2015). This post provides a brief summary of the Ultra Resources decision. Check back to this web site soon for our more in-depth analysis of the Ultra Resources decision.

If the compressor stations were aggregated as a single source, their emissions would have exceeded major source thresholds, and Ultra would have been required to obtain a single, more stringent, major-source air permit for the compressor stations. Under Pennsylvania regulations, as under EPA regulations, compressor stations are considered a single source for air permitting purposes only if they are under common control and are contiguous or adjacent. 40 C.F.R. § 70.2 (defining “major source”); 25 Pa. Code § 121.1 (defining “facility,” “major facility,” and “Title V facility”). The sole issue in dispute in Ultra Petroleum was whether the compressor stations were “adjacent” to one another. The parties stipulated to the distance between the compressor stations (ranging from 0.78 to 4.43 miles).

In granting summary judgment to Ultra, the court found that a determination of adjacency should focus on the plain meaning of the term, requiring physical proximity. Based on the plain meaning of the word “adjacent,” the court held that Ultra’s compressor stations were not adjacent to one another as a matter of law. The court rejected PennFuture’s argument that the compressor stations were “adjacent” by virtue of being “functionally interrelated” solely because the eight compressor stations deposit gas into a common pipeline.

In reaching its determination in Ultra Petroleum, the court cited PADEP’s “Guidance for Performing Single Stationary Source Determination for Oil and Gas Industries” (DEP ID: 270-0810-006), 42 Pa. B. 6344 (Oct. 6, 2012); Sixth Circuit case law in Summit Petroleum Corp. v. EPA, 690 F.3d 733, 735 (6th Cir. 2012), in which the Sixth Circuit interpreted “adjacency” to require physical proximity and could not be shown by functional relationships among facilities; and Nat’l Envtl. Dev. Ass’n’s Clean Air Project v. EPA, 752 F.3d 999 (D.C. Cir. 2014), in which the D.C. Circuit extended the Summit Petroleum decision nationwide. Norton Rose Fulbright’s past discussions of Summit Petroleum and NEDACAP are available on our web site.

The Ultra Resources court agreed with the majority in Summit Petroleum that the plain meaning of “contiguous” and “adjacent” should normally operate to allow a determination as to whether stationary sources should be aggregated. Departing from Summit Petroleum and NEDACAP, however, the court left open the possibility that, under PADEP guidance, a court in Pennsylvania might still consider “functional interrelatedness,” but only in unique factual situations beyond the normal oil and gas configurations and arrangements contemplated by PADEP.

This article was prepared by Janet McQuaid (janet.mcquaid@nortonrosefulbright.com or +1 724 416 0427) , Jeremy Mercer (jeremy.mercer@nortonrosefulbright.com or +1 724 416 0440) and Bob Greenslade (bob.greenslade@nortonrosefulbright.com / +1 303 801 2747) from Norton Rose Fulbright's Energy Practice.

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