Environmental Law ReSource : Environmental Lawyer & Attorney : Reed Smith Law Firm : Climate Change, Sustainability

This post was written by Todd Maiden, Donald Ousterhout and Brendan McNallen.

On October 20, the California Air Resources Board ("CARB") approved the final regulation for the California cap-and-trade program authorized by California's Global Warming Solutions Act (AB 32). As anticipated, CARB approved recent modifications to the regulation proposed in July and September 2011, paving the way for a cap-and-trade program with a compliance start date of January 1, 2013 for most entities covered by the regulation.

Under the cap-and-trade program, certain facility operators, including the operators of electricity generating facilities located in California, electricity importers and self-generators of electricity, will need to comply with California's mandatory reporting regulation if such entity's reported annual emissions in any year from 2008 to 2011 equal or exceed thresholds identified in the regulation. The applicability threshold for most facility operators, including electricity generating facilities, is currently set at 25,000 metric tons or more of carbon dioxide equivalent ("CO2e") per data year. An entity that has emissions from combustion of biomass-derived fuels is required to report and verify its emissions under the mandatory reporting regulation, but emissions from certain source categories (including the geothermal generating units and facilities) and certain biomass fuels (including biodiesel, fuel ethanol and agricultural crops or waste) will not be subject to the compliance obligation.

An entity that meets or exceeds the thresholds in the regulation in any year from 2008 to 2011 must register with CARB by January 31, 2012. An entity cannot hold a compliance instrument discussed below until the CARB Executive Officer approves the entity's registration.

The final regulation incorporates modifications to the regulation proposed in July and September 2011, including adjusting the start date for the first compliance period from January 1, 2012 to January 1, 2013. A covered entity must surrender one compliance instrument for each metric ton of CO2e emissions to meet its annual and triennial compliance obligations (as calculated pursuant to formulas set out in the regulation) beginning with the emissions data report for 2013 emissions, and for each subsequent year in which the covered entity has a compliance obligation.

Compliance instruments include allowances, CARB offset credits or sector-based offsets credits. Two auctions for emissions allowances are slated for 2012—on August 15 and November 14—and auctions will then be held quarterly beginning in 2013. The final regulations set forth the requirements for, and procedures for obtaining, CARB-issued offset credits, registry offset credits and sector-based offset credits, including the requirement that greenhouse gas emission reductions must be real, additional, permanent, quantifiable, verifiable and enforceable.

If you would like additional information about the California cap-and-trade program or have questions about your company's compliance obligations, please contact one of the the authors.

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This post was written by Jennifer Smokelin.

The U.S. Environmental Protection Agency (USEPA) announced today that it will propose a rule for wastewater from coal bed methane in 2013 and a proposed rule for shale gas wastewater in 2014. The announcement is part of the effluent guidelines program (Clean Water Act § 304(m)), which sets national standards for industrial wastewater discharges based on best available technologies that are economically achievable.

To ensure that these wastewaters receive proper treatment and can be properly handled by treatment plants, USEPA will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for coal bed methane and for shale gas. The time frame for coal bed methane is shorter because USEPA feels it already has a leg up on data necessary for the coal bed rule whereas there is more information to gather with regard to shale gas wastewater.

A Few More Details

Hydraulic fracturing is a method of releasing natural gas from highly impermeable rock formations by injecting large amounts of fracturing fluids at high pressures to create a network of fissures in the rock formations and provide the natural gas a pathway to travel to the well for extraction. Geologic pressure within the shale formation forces these fracturing fluids back to the surface, where they are referred to as “produced water” or shale gas wastewater. Based on a review of available data, USEPA is initiating a rulemaking to control wastewater produced by natural gas extraction from underground shale formations. Under this proposed rulemaking, EPA will consider standards based on demonstrated, economically achievable technologies, for shale gas wastewater that must be met before going to a treatment facility.

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This post was written by Siobhan Hayes.

In a number of the recent UK Government publications on shale gas the statement has been made that land owners in the UK do not own the mineral rights to petroleum under their land (under the relevant statute this includes mineral oils, hydrocarbons and natural gas in their natural condition in sub surface strata). Potential exploiters of shale gas will be granted licences by the Government to explore and exploit shale gas reserves but their project planning will need to understand that without proper procedures being followed it is possible for them to be exposed to actionable trespass even where wells are drilled under licence.

Historically, property owners in England and Wales own the surface of the land and the heavens above and strata below. How far down that ownership extends has been the subject of recent case law (Star Energy v Bocardo in 2010). In the Star Energy case, the Supreme Court ruled that an oil company had trespassed on an owner’s land by drilling from a well head close to the boundary of the two properties diagonally downwards and under the adjoining land. One of the strange features of trespass is that damages are paid to the occupier or owner whether or not they have suffered damage.

The oil company had not negotiated any consent from the neighbour and they had not applied for the relevant statutory rights to do so. The land owner was therefore entitled to damages. The good news outcome for those extracting oil or gas onshore is that compensation was assessed on the least costly basis. It was assessed as the value that would be paid if the right to drill had been compulsorily acquired. There was a procedure under which the oil company could have made a claim for a statutory right to drill the well but they had not done this. The compensation did not depend on the value that the oil company got from using the wells. It was a hard fought battle that resulted in a 3:2 split between the Supreme Court Judges.

The legislation which gives oil companies the rights to extract oil and gas in practice was drafted before there were thoughts of shale gas development and the shale gas industry may want to consider seeking a change in this part of the law to address concerns specific to shale gas exploration.

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This post was written by Larry Demase, Lou Naugle and Jennifer Smokelin.

Yesterday, we reported on the Pennsylvania Department of Environmental Protection’s (DEP) announcement of a proposed technical guidance for single stationary source determinations for oil and gas operations (the Single Source Guidance). Here’s our analysis of the proposal, including some background information, a discussion of the guidance and our thoughts on its potential impact.

Background

First, you should know that aggregation is the process of determining whether emissions from multiple operations should be aggregated into a single source for air permitting purposes. A significant issue related to oil and gas operations is whether emissions from individual operations such as wells, processing plants and compressor stations should be combined so that they become major sources for permitting purposes, subject to Title V requirements and New Source Review. When aggregation is at issue, individually the operations are not considered “major” for any contaminant.

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This post was written by Larry Demase and David Wagner.

Last week, the U.S. Supreme Court let stand a ruling that CERCLA’s contribution section (Section 113(f)) provides the exclusive remedy for a liable party compelled to incur response costs under an administrative settlement. In Morrison Enterprises, LLC v. Dravo Corporation, No. 11-30, Morrison Enterprises (Morrison) filed a petition for certiorari before the U.S. Supreme Court, asserting a conflict in the Circuit Courts of Appeal and with two seminal Supreme Court decisions. Reed Smith represented Dravo Corporation in opposing the petition and the Supreme Court denied certiorari on October 3.

In the case, Morrison and the city of Hastings, Nebraska – both of which were liable under CERCLA for hazardous substances released into the groundwater – sued Dravo Corporation, a manufacturing site owner also liable under CERCLA. Morrison and the City filed suit under CERCLA Section 107 and sought to recover groundwater contamination costs related to the operation of Well D, a groundwater extraction and treatment system located downgradient of each party’s relevant source of contamination. The District Court granted Dravo Corporation’s motion for summary judgment, finding that Section 113(f) was the Appellants’ exclusive remedy. The Circuit Court affirmed, explaining that “liable parties which have been subject to Section 106 or 107 enforcement actions are still required to use Section 113.” In ruling for Dravo Corporation, the circuit court held that, because Morrison and the city of Hastings were liable parties compelled to incur response costs pursuant to an administrative or judicially approved settlement under Sections 106 or 107, they could only bring a Section 113(f) claim for contribution. See Morrison Enterprises, LLC v. Dravo Corporation, 683 F.3d 594 (8th Cir. 2011).

Dravo Corporation was represented by Reed Smith attorneys Larry Demase, Jim Martin, David Wagner and David Bird. Additional case details can be found on our blog at this post.

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This post was written by Nicolle Snyder Bagnell and Ariel Nieland.

The Pennsylvania Department of Environmental Protection announced today that it has submitted its technical guidance for single source determinations for oil and gas operations to the Pennsylvania Bulletin for public comment. The Department's guidance deals with the determination of whether two or more stationary sources should be aggregated together and treated as a single source of air emissions for the purposes of air permitting requirements. Specifically, the guidance involves three sets of regulations: the federal Prevention of Significant Deterioration, or PSD, regulations; the Pennsylvania nonattainment New Source Review regulations; and the Title V program. Click here for the full text of the technical guidance.

The public may comment on the air aggregation determination guidance until November 21, 2011.

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This post was written by David Wagner.

On Wednesday, Reed Smith held its quarterly environmental and energy law resource teleseminar and the slides and audio are available. We discussed current or emerging issues under five general categories. The categories and discussion included:

• Legislation/Rules — We reviewed the key points and effective dates related to the New Source Performance Standards for the oil and gas industry as well as for utilities and refineries.
• Litigation — A big environmental litigation issue involving the oil and gas industry is the aggregation of air emissions from diverse sources and we discussed recent challenges to air permits involving this issue. We also discussed the U.S. Supreme Court's recent denial of certiorari in Morrison Enterprises v. Dravo Corporation and the implications on CERCLA cost recovery and contribution claims.
• Policy and Technology — On this front, our presentation focused on a recent DOE report on the need for additional disclosure, and the policy implications related to the interplay between the U.S. Environmental Protection Agency and Federal Energy Regulatory Commission.
• International Issues — Here we provided a brief preview of the upcoming COP in South Africa and the fate of the Kyoto Protocol
• State Issues — On the state level, we focused on California and summarized recent developments regarding the implementation of the California Global Warming Solutions Act (aka AB32) and California's “Green Chemistry” Initiative.
   

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This post was written by Jennifer Smokelin.

Our blog has discussed the U.S. Department of Energy's creation of a panel to examine exploration and extraction in the Marcellus Shale (and I discussed the matter in more detail in my July article in The Legal Intelligencer ’s annual Energy Law report -- titled "The Frack Panel: Drilling Down on Representation and Timing Issues"). On October 4, members of the Frack Panel testified in front of the Senate Energy and Natural Resources Committee and would not commit to endorsing either state or a federal regulation as preferable for shale drilling. The panel, created earlier this year by Steven Chu, the Secretary of the U.S. Department of Energy Secretary, was originally tasked to make recommendations about how to make drilling safer, particularly hydraulic fracturing and offer advice to other agencies on how they could better protect the environment from shale gas drilling. Increasingly, the panel has been brought into the state-vs.-federal regulation of shale gas drilling debate.

The testimony comes on the heels of an Intermim Report drafted by the 7 member panel that was published in August. Four of the seven subcommittee members who wrote the report testified at the Senate hearing this week, including Chairman of the IHS Cambridge Energy Research Associates Dr. Daniel Yergin. While the group recommended some federal oversight of safety standards and best practices, and outlined 20 recommendations for the hydraulic fracturing, or "fracking," industry, the witnesses generally expressed opposition to federal regulation of fracking, suggesting state level oversight and industry self-regulation was, in nearly all cases, preferable.

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This post was written by Nicolle Bagnell and Ariel Nieland.

Yesterday, Pennsylvania Governor Tom Corbett finally released his new Marcellus Shale oversight plan, much of which is based on the Marcellus Shale Advisory Commission's report provided to him in July. Gov. Corbett's plan provides for a county-assessed annual impact fee of $40,000 per well during the first year of production. The fee would decrease to $30,000 and then $20,000 for the second and third years of production respectively. After that, producers would be assessed at $10,000 per well for the subsequent seven years. The estimated $120 million in revenue generated from the fee in its pilot year would be distributed primarily to counties and municipalities hosting natural gas drilling, with the remainder going to state agencies such as PennDOT, the Pennsylvania Emergency Management Agency, the State Fire Commissioner, the Department of Health, the Public Utility Commission, and the Department of Environmental Protection. The Corbett administration estimates that the fee would generate up to $195 million by the sixth year.

In addition to the impact fee, Gov. Corbett also proposes to increase the minimum setback distance between gas wells and water supplies as well as expand the presumption of liability distance for producers from 1,000 feet to 2,500 feet. In addition, bond payments and penalties for civil violations would be stepped-up. The Governor's plan also incentivizes schools and mass transit systems to convert to natural gas for fuel and provides for natural gas fueling stations every 50 miles along new "green corridors" throughout the state.

The next step is for the plan to go before the Pennsylvania legislature for approval and state agencies for execution.

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