Federal EPA: Cattle methane emissions top oil and gas industry. The Environmental Protection Agency (“EPA”) published its draft greenhouse gas inventory, issued under the United Nations Framework Convention on Climate Change. The inventory identifies the cattle industry (141 million metric tons CO2e) as the country’s largest source of methane emissions, with the oil and gas industry estimated at 127.1 million metric tons CO2e. EPA noted that oil and gas methane emissions have decreased 17% since 1990, despite the nearly decade-long boom in production. EPA cited voluntary methane controls and the replacement of old cast-iron distribution lines for the reduction. Overall, U.S. greenhouse gas emissions decreased by 3.3% in 2012 compared to the prior year. EPA attributed the reduction, in part, to increasing reliance on natural gas over coal for electricity generation. EPA: Revisions to GHG reporting for oil & gas sector proposed. EPA posted a pre-publication version of amendments to Subpart W, the regulations governing how the oil and gas sector calculates and reports its GHG emissions. The draft proposes to eliminate by January 1, 2015 the use of “best available monitoring methods,” an alternative emissions methodology allowing covered entities to use an array of available data, such as supplier information or engineering calculations, to estimate emissions. Instead, the sector would have to use more stringent monitoring and quality assurance methods. Covered entities would also be required to report individual GHG emissions instead of reporting only the total carbon dioxide-equivalent of those emissions. Revisions also included changes to the source definition, the sub-basin category definition, and calculation methods for individual equipment used at oil and gas well sites. EPA stated that the changes would improve consistency in the data it collects for its GHG inventory. The proposed rule will be open to public comments for 45 days after it is published in the Federal Register. DOT: Emergency order for crude oil testing. The U.S. Department of Transportation (“DOT”) issued emergency orders requiring rail shippers to test crude oil to ensure proper shipping classification and prohibiting crude oil from being classified under the Class 3, Packing Group III category, which is reserved for relatively safe cargo. Instead, crude oil would be classified as Packing Group I or II. Although this will not impact how crude oil is handled or shipped, it will require railroads to prepare for worst-case accident scenarios. The order comes after the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a safety alert determining that light Bakken crude oil is more flammable than heavier crude oils. Concerns have been raised that the language of the emergency order was too vague to inform companies how to conduct the testing, but PHMSA responded that shippers will determine the proper testing methods, because the composition of tight oil can differ from shale play to shale play. DOT: New voluntary regulations for crude oil rail shipping. DOT and the railroad industry negotiated a new set of voluntary standards for tanker cars hauling crude oil. Under an agreement between DOT and the Association of American Railroads, railroads will perform an additional internal rail inspection and two additional track geometry inspections each year for main line routes and install two-way telemetry braking devices, allowing easier application of emergency brakes. Those measures will go into effect next month. By July 1, 2014, railroads will adopt new wheel bearing detectors, a government-developed risk analysis tool called the Rail Corridor RiskManagement System that will evaluate the safety and security of routes for trains hauling crude oil, and inventory emergency resources for responding to emergencies involving crude derailments. Additional standards, such as those for tank cars and shipper classifications, will be addressed in the future. BLM: San Juan Basin plan will be reviewed. The U.S. Bureau of Land Management will update the resource management plan (“RMP”) for northwest New Mexico’s San Juan basin in light of increased shale development. Oil and gas development have been a major part of the Basin for over 90 years, but companies are now exploring the underlying Mancos Shale and Gallup Sandstone formation, which some estimate to have significant oil production potential. Exploratory drilling and plans for further development prompted BLM to announce that it will examine the potential impacts on air quality, roadless lands, wildlife, recreation, and water supplies. Based on this examination, the RMP will evaluate whether areas should be closed to shale development and what mitigation measures would be necessary for drilling operations. The RMP was last updated in 2003. EPA: NGO petitions for changes to off-shore discharge practices. The Center for Biological Diversity submitted a petition to the EPA Administrator requesting that the general permit covering California offshore oil and gas operations be amended to prohibit the discharge of chemicals used in hydraulic fracturing fluids. The petition alleges off-shore oil operators discharge these chemicals into habitat for endangered species. To date, approximately 12 platforms off the coast of California have been authorized to discharge hydraulic fracturing wastewater. The general permit at issue was recently amended to require operators using hydraulic fracturing fluids to inventory the chemicals and report any released into the marine environment. States California: Investigation launched into produced water storage. California’s Central Valley Regional Water Quality Control Board issued investigative orders to 78 companies conducting hydraulic fracturing in the Central Valley. The investigation began after a YouTube video surfaced showing a truck allegedly discharging produced water into an unlined pond in violation of the Water Quality Control Board’s regulations. Vintage Production was fined $60,000 and ordered to study the pit and determine if groundwater was impacted. The Water Quality Control Board is now investigating how common the practice is among area drilling companies. Colorado: State approves methane regulations. Colorado became the first state to directly regulate methane emissions from oil and gas operations. The new rules will require, among other things, monthly inspections for larger gas processing operations, as well as a methane leak detection and repair program for pipelines, storage tanks, and various process equipment. Overall, they impose a wide array of new emission rules and practices governing glycol dehydrators, pneumatic devices, and other process components. The new regulations are also expected to reduce 92,000 tons of volatile organic chemical emissions, which contribute to ground level ozone formation. The Colorado Air Quality Control Commission worked with the Environmental Defense Fund and drilling companies heavily invested in the state to negotiate the rules. A spokesman for the Environmental Defense Fund touted the regulations as a model for other states to adopt; however, industry trade associations that were not involved in the negotiations stated that the rules were unnecessary, based on outdated information, and had no health benefits. Pennsylvania: PA Supreme Court denies trial in Act 13 litigation. The Pennsylvania Supreme Court denied a motion by the Commonwealth’s solicitor general to remand the case that invalidated Pennsylvania’s Act 13 to a lower court for a trial on undeveloped factual issues. The court previously struck down the law, in part, a law which established comprehensive state oil and gas regulations for environmental protection, fees, and chemical disclosure, as unconstitutional. The case was remanded so the lower court could determine if any surviving portions of the law can operate independently of those sections that were invalidated. Business Chesapeake may spin-off or sell oil field services division. Reportedly, in its drive to continue paying down debt, Chesapeake Energy is contemplating the fate of its oil field services division. Chesapeake previously considered an IPO for the division in 2011, but a drop in gas prices saw other well field service companies crowding into the oil market. Now, with $2.2 billion in revenue last year, Chesapeake stated that a spin-off or sale of the division can reduce complexity within the company while maximizing shareholder value.
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