This week in hydraulic fracturing

Federal

Government shutdown has had a limited impact to date on drilling on federal lands. The government shutdown resulted in the furlough of most Bureau of Land Management (“BLM”) employees, some of whom process oil and gas drilling permits for federal lands and Indian reservations, including the Fort Berthold reservation in the Bakken Shale play. A spokeswoman for industry group Western Energy Alliance shrugged off the delays, noting that most companies can wait a year or more for permits to drill on federal land, limiting the impact of a relatively short shutdown. Several environmental groups have criticized the National Park Service for allowing oil and gas companies that have permits to continue operating in national parks that are closed to the public. Industry and the Park Service, however, responded that many operators have shut wells during the shutdown or are operating from private lands within the parks.

NGOs ask BLM to stop California leasing. A group of environmental NGOs have asked the U.S. Bureau of Land Management to cancel all existing oil and gas leases on federal land in California until BLM finishes an analysis of hydraulic fracturing. BLM previously cancelled all California oil and gas leasing from May through September 2013, citing the budget sequester. The NGOs want BLM to extend this stoppage until an environmental impact statement and scientific review on hydraulic fracturing in California is completed. The Western States Petroleum Association disputed the claims by NGOs that hydraulic fracturing presents unknown hazards, noting the practice has been done safely in California for decades and that the state just passed legislation providing for new regulation.

Offshore hydraulic fracturing challenged. The Center for Biological Diversity is urging the federal Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement to shut down offshore operators that use hydraulic fracturing or face a lawsuit. The group claims that any authorization for offshore hydraulic fracturing must be vetted through the National Environmental Policy Act and other federal laws, arguing that hydraulic fracturing threatens ocean wildlife. 

U.S. will pass Russia as the top oil & gas producer this year. The Wall Street Journal reports that Russia, facing declining output from conventional oil and gas fields, is expected to lose its title as the top oil and gas producing country. Although the U.S. is not currently exporting oil or gas in significant numbers, the amount it imports has dramatically declined over the past few years, making more available for other countries. Increases in U.S. gas exports, through liquefied natural gas (“LNG”) export terminals and increased pipeline shipments to Mexico, could further erode the clout of the Gazprom (owned by the Russian government) and other producers. At the same time, Russia has shale formations that may be developed in the future, while the U.S. could see its shale production impacted by lower prices, increased regulation, and NGO opposition. 

States

Ohio chemical reporting law yields to federal reporting regulations. The Ohio Environmental Protection Agency (“Ohio EPA”) has agreed with US EPA that a 2001 state law, requiring oil and gas drillers to report chemicals used in hydraulic fracturing fluid to the Ohio Department of Natural Resources, did not satisfy federal reporting requirements under the Emergency Planning and Community Right-to-Know Act (“EPCRA”). Under EPCRA, a site that stores at least 10,000 pounds of any chemical designated as “extremely hazardous substances” by OSHA must report to local first responders. Oil and gas companies were informed they need to begin reporting covered chemicals under EPCRA, while Ohio EPA considers whether its own rules require a legislative or regulatory amendment to satisfy federal law.

Oklahoma disposal well closed after seismic activity. The Oklahoma Corporation Commission (“OCC”) ordered an underground injection disposal well near Marietta, Oklahoma to shut down after OCC recorded a series of tremors near Marietta, Oklahoma. The well had only started operations two weeks before the tremors which peaked at magnitude 3.4 and damaged nearby buildings. The Oklahoma Geological Survey stated that earthquakes increased as the well’s injection volumes increased, but that further investigation is needed. The well operator stated the well was also shut down because it was uneconomic. Before start-up, OCC had severely limited wastewater injection volume and pressure as part of a cautious approach to regulating new wells.

Colorado inspectors continue to monitor spills in flood’s wake. Inspectors from the Colorado Oil & Gas Conservation Commission (“COGCC”) continue to review the integrity of nearly 1,900 wells previously underwater from flooding. COGCC has reported 15 spills that released approximately 43,000 gallons of oil and 18,060 gallons of wastewater. Damaged roads have slowed the inspectors, who still need to assess some wells in the Wattenberg Field. Companies are also starting to put dollar values on the flood damage, with Noble Energy, the state’s biggest oil producer, putting its losses at $7-17 million in damaged equipment and lost production. Rep. Jared Polis (D-Colo.) is seeking Congressional hearings to investigate the impact of drilling site releases. By contrast, Colorado Gov. John Hickenlooper, Colorado environmental officials, and an EPA Region 8 spokesman characterized them as small when compared to the large amounts of raw sewage and household chemicals released during the floods.

Business

Shell selling off Eagle Ford shale assets. Shell is putting its Eagle Ford Shale play assets up for sale, as the company has failed to profit consistently from these assets. Its relatively late entry left it with areas that were more challenging to develop and produced more natural gas than oil at a time of low gas prices. The sale comes after the company wrote down $2 billion in value for its shale assets and prompted an earlier sell-off of its Mississippi Lime formation assets. The assets include 106,000 acres across three Texas counties and 192 wells that also produce approximately 32,000 barrels of oil and natural gas liquids per day. 
Devon Energy takes pipeline spin-off public. Devon Midstream Partners LP, a new master limited partnership, will soon go public, hoping to raise $400 million. The new MLP will own approximately 20% of Devon Energy’s existing pipeline assets and will acquire more of Devon’s assets over time. Devon Energy currently transports 2.9 billion cubic feet of gas per day through its 3,600 miles of pipeline and owns gas processing plants throughout Texas and Oklahoma.

Some private equity groups still bullish on U.S. shale. Private equity deals for shale assets reportedly reached $30 billion in 2012. Yet, while some private investors have cooled to new shale investments in 2013 due to low gas prices, industry consolidation, and the maturing of shale plays, others reportedly see significant additional investment opportunities, particularly as hydraulic fracturing provides access to new deposits through new and evolving technologies. Some suggest hydraulic fracturing could revitalize conventional reservoirs, such as Prudhoe Bay. Others predict that shale plays could attract large upstream and midstream investments in the next 20 years, including significant private equity investors. Private equity managers typically seek out investments in smaller drilling, service, or equipment manufacturing companies, but some analysts believe there will be larger private deals in coming years.

Research

Natural Gas Supply Association forecasts a mild winter will depress gas prices through 2014. A forecast of natural gas demand over the winter of 2013 to 2014 predicts that gas prices will stay relatively low. The Natural Gas Supply Association (“NGSA”) estimates that gas demand will be comparable to last winter, where gas prices averaged $3.47/ MMBtu. This would likely result in a continued reduction in rig counts for dry gas shale plays as companies shift to more profitable crude oil and gas liquids plays. The forecast also sees electricity production slightly shifting back to coal-fired generation which becomes more competitive when gas prices hit approximately $3.50/ MMBtu. Coal-fired generation has already increased by 14% in the first half of 2013. NGSA’s long-term forecast predicts a major spike in natural gas demand by 2020 due to increased pipeline shipments to Mexico, LNG exports, and new industrial facilities coming on-line. Under this demand “super cycle,” gas prices could increase to as high as $7/MMBtu in the short term until companies can ramp up dry gas production.

Study: Radioactive isotopes found near Pennsylvania treatment plant. A Duke University study published in Environmental Science & Technology found Radium-226 and Radium-228 in creek sediment downstream of the Josephine Brine Treatment Facility. The authors conclude that hydraulic fracturing wastewater, which was previously treated at the Josephine facility, was responsible for the isotopes’ presence based on chemical fingerprinting. The Pennsylvania DEP discovered the isotope in the sediments in July 2011. Fluid Recovery Services, which owns and operates the Josephine facility, is currently remediating the creek under a consent order with DEP. Fluid Recovery also agreed to spend up to $30 million in plant upgrades, and settled Clean Water Act claims brought by U.S. EPA for $83,000. Pennsylvania has prohibited treatment plants from accepting hydraulic fracturing wastewater since September 2011.

Study: Hydraulic fracturing improvements could yield big gains. A preliminary report by Higgs-Palmer Technologies shows that companies are leaving a substantial quantity of natural gas in shale formations due to inefficient hydraulic fracturing techniques. Microseismic data show a significant decrease in permeability occurs between well stimulation and gas production. Its analysis postulates that more proppant should be used during the well completion stage, and that the proppants used should be smaller, as data in some instances suggest up to 90% of available gas is being left in the rock. Higgs-Palmer is developing software that could better measure shale permeability during various phases of well stimulation and completion.