Energy Business Law : Energy Lawyers & Attorneys: McDermott Will & Emery Law Firm

by Rashpaul Bahia

On May 8, 2012, STX Services B.V. (STX), launched an electronic trading platform for the sale and purchase of renewable energy certificates relating to power consumption within the European Union. 

The new platform will allow for the trading of Guarantee of Origin (GoO) certificates which provide proof to the final customer that the energy produced was from renewable sources.  GoO certificates were introduced by the 2009 EU Renewable Energy Directive. One GoO certificate represents the generation of one megawatt hour of electricity.

STX, an Amsterdam-based brokerage firm dealing in environmental based commodities, held its first auction on May 8, 2012 and is likely to hold another one towards the end of May 2012.  STX has stated that it hopes to eventually run daily auctions, and expand to include other renewable energy certificates.

STX feels that the advantages of the new trading platform are that:

• buyers and sellers of GoO certificates can participate concurrently;
• buyers and sellers can login to the platform from wherever they are located;
• the supply and demand dynamic of the online auction will result in the realization of a true and fair market price; and
• it provides greater liquidity in an otherwise fragmented international market.

More than 25 percent of the most active market participants attended the first auction, during which 100,000 GoOs were bought and sold at a clearing price of €0.37.  Participants in this first auction pointed to, amongst other things, the transparency and efficiency engendered by the new platform.

The launch of this new trading platform comes at a time when the European Commission is actively looking at ways to regulate and increase the transparency of commodity markets.  Proposals include establishing transparent trading venues. STX has designed its new platform with this in mind, and hopes that it will enable all participants to buy and sell renewable energy certificates on a level playing field.

In addition, the new platform represents a further development and expansion in the trading of green power. 

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by Prajakt Samant and Simone Goligorsky

On April 27, 2012, the European Commission (EC) announced the full activation of the EU Emissions Trading System (EU ETS) single registry.  The full activation process will include the migration of over 30,000 EU ETS accounts from national registries.

On May 3, 2012, the EC provided the following transition table in relation to the full activation:

• Starting on May 14, account holders (including aircraft operators) will not be able to open or close accounts or to modify accounts and account representative details, neither in national registries nor in the single registry.
• From June 3, the operation of national registries and the single registry will be suspended simultaneously and account holders will not be able to access registry accounts, including allowances held in these accounts.  Data held by the national registers will start to be migrated to the EU registry.
• On June 20, the single registry will be fully activated.  Users of existing national registries will be able to use the single registry as soon as they receive their new authentication credentials from their national administrator.

This will impact account holders in two ways.  First, account holders will have to comply with increased documentation requirements and security features to access the transferred accounts in the single registry.  Second, account holders will not be able to transfer any allowances until all necessary documentation requirements are satisfied.

In addition, the EC announced that in the event that account holders have any questions or difficulties during the transition, national helpdesks will continue to provide support.  The Environment Agency will continue to be the national administrator for the UK. 

The EC has further stated that the single registry to be activated in June will not contain all the required functionalities for phase III of the EU ETS.  A subsequent update will enable phase III auctions, new account categories and a trusted account list.  The EC has stated that software development in relation to these updates has been commenced and a timetable will be communicated on July 15, 2012.

Separately, on May 8, 2012, the UK Department of Energy and Climate Change launched a public consultation on the implementation of phase III EU ETS in the UK.  The consultation seeks the views of market participants on how the proposed legislative framework should be successfully implemented in the UK.  By simplifying the existing legislative framework, market participants will be subject to less of a regulatory burden than has been imposed by the current regime.  Market participants wishing to respond have until July 31, 2012 to do so.

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by Bradford K. Gathright

On April 20, 2012, the Federal Energy Regulatory Commission (FERC) issued an order confirming that it has no jurisdiction under the Federal Power Act (FPA) with respect to sales of state-issued renewable energy credits (RECs) that are not bundled with sales of wholesale energy, but asserted that it does have jurisdiction over sales of RECs that are bundled with wholesale energy.

The ruling was in response to a request by the Western Systems Power Pool (WSPP) for FERC to clarify the scope of its jurisdiction. WSPP administers a standardized contract, called the WSPP Agreement, for the sale of wholesale electric power and physical options between its members. The WSPP Agreement allows a seller to charge market prices in energy transactions if the seller has received market based rate authority from FERC or if the seller is not regulated by FERC. Otherwise, the price is subject to rate caps set forth in the applicable FERC-approved rate schedule to the WSPP Agreement.

On February 22, 2012, WSPP submitted for approval under Section 205 of the FPA a revised service schedule to the WSPP Agreement, Service Schedule R, to address several varieties of bundled and unbundled REC transactions. For bundled REC transactions, the rate caps set forth in the existing service schedules of the WSPP Agreement would apply only to the energy portion of the contract price if the total price was allocated separately between energy and RECs, or to the total contract price if there were no separate allocations. With regard to unbundled REC transactions, the WSPP requested that FERC confirm its lack of jurisdiction.

In its order, FERC approved the incorporation of Service Schedule R into the WSPP Agreement and confirmed that sales of RECs that are not bundled with sales of wholesale energy fall outside FERC’s jurisdiction under Sections 201, 205 and 206 of the FPA. FERC’s rationale was that a REC is simply an instrument of state law certifying that energy has been generated pursuant to certain standards, and that the sale of a REC does not constitute the transmission of electric energy or the sale of energy in interstate commerce. However, when RECs are bundled with sales of energy, the REC transaction falls within FERC’s jurisdiction because the REC sales “affect” and are “in connection with” the wholesale energy sales. Under these circumstances, FERC asserted that it has jurisdiction over both the wholesale energy portion and the REC portion of the bundled transaction, regardless of whether the contract price is allocated separately between the energy and the RECs or whether the energy portion and the REC portion of a bundled transaction are split into two separate contracts.

The practical implications of the order are not yet clear. By extending its jurisdiction to RECs at all, FERC has expanded its reach and now has the authority to create additional requirements relating to the REC portion of a bundled REC transaction, which could increase the administrative and financial burden of selling RECs. For power producers who are selling bundled RECs and already have market based rates, the order will likely not have much of a practical impact, other than perhaps changing how bundled RECs are described in periodic FERC reports, a subject that has not yet been addressed.

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by Ari Peskoe

In a joint-rulemaking finalized last month, the Commodities Future Trading Commission (CFTC) and the Securities Exchange Commission (SEC) declined to adopt specific exemptions for the electricity industry in its definitions of “swap dealers” and “major swap participants.” It is likely, however, that many industry participants will be able to take advantage of exemptions for swaps entered into for the purpose of hedging price risks related to physical positions and the de minimis exception, or that relevant transactions will be excluded from the definition of the term “swap.”

Comments submitted by the industry on the proposed rule argued that the many unique characteristics of swaps related to electricity markets entitled them to special treatment by regulators.  For example, as opposed to many other physical commodities, electricity must be generated and transmitted at the instant it is needed, and while demand for electricity is relatively price inelastic, demand at any moment in time can fluctuate based on a range of variables, such as weather and time of day. As a result, the use of swaps related to electricity is different from the use of swaps for other physical commodities in that electricity swaps are more highly customized to a particular place and time and are more likely to relate to a short time period or be more frequently entered into. Commenters also noted that electricity markets are already subject to regulation by Federal, regional and state regulators. In addition, electric cooperatives requested that they be excluded from the definition of a swap dealer because they are not-for-profit entities that enter into swaps for the benefit of their members, do not hold themselves out as swap dealers, do not make markets and their swaps are not necessarily reflective of market rates.

While the final rule does not include any exemptions specific to the electricity industry, the preamble notes that “a significant portion of the financial instruments used for risk management by such persons [who transact in swaps related to the generation, transmission and distribution of electricity] are forward contracts in nonfinancial commodities that are excluded from the definition of the term swap.”  The CFTC has not yet released the final version of another rule defining the term “swap.”

With regard to swaps entered into for hedging purposes, the CFTC adopted the principles of bona fide hedging that it has long applied to identify when a financial instrument is used for hedging purposes, and excluded from the swap dealer analysis swaps entered into for the purpose of hedging physical positions. The CFTC adopted the physical hedging exclusion on an interim basis and is still seeking comment on how swaps entered into for hedging may be distinguished from swaps entered into for other reasons, such as speculation. Note that the Commodity Exchange Act explicitly excludes positions held for “hedging or mitigating commercial risk” in the determination of whether an entity is a major swap participant. 

Many industry participants can be expected to use the de minimis exception to avoid regulation as a swap dealer.  The final rule sets a de minimis threshold for swap dealing activity over the prior 12 months at a gross national value of $3 billion. An interim $8 billion limit will be in effect for at least the first few years after the rule is implemented. 

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by James A. Pardo and Brandon H. Barnes

Obama Signs Executive Order Creating Hydraulic Fracturing Task Force

President Obama’s position that hydraulic fracturing must be conducted in a "safe and responsible" manner has been interpreted as suggesting the need for increased federal regulation of fracing. Indeed, various federal agencies have stepped forward with proposed regulations targeting air emissions, chemical disclosures, wastewater handling and other fracing-related issues.  Many natural gas stakeholders have expressed concern about this building wave of federal regulation, from different agencies and regulators, and the potential that this will result in inefficient, burdensome and even conflicting federal-versus-federal and federal-versus-state regulatory requirements. 

Perhaps in response to these concerns, on April 13, President Obama signed an executive order creating a task force of 13 federal agencies to "coordinate the efforts of Federal agencies responsible for overseeing the safe and responsible development of unconventional domestic natural gas resources and associated infrastructure and to help reduce our dependence on oil ...." While some in the oil and gas industry have applauded the creation of this task force for its potential to streamline and coordinate federal activity on fracing, stakeholders will keep a close eye on the path taken by the Obama Administration.  Since 2005, the bulk of hydraulic fracturing oversight has come from state regulatory authorities – who typically are better positioned to deal with the unique regional and local issues often presented by oil and gas development. 

Requiring coordination among 13 different federal agencies may be a positive development. However, the precedent of federal regulation – and the possibility that coordination may lead to calls for more regulation in the future – may be one that stakeholders will be less than enthusiastic about, particularly after the Environmental Protection Agency wraps up its multi-year study of fracing's impacts on groundwater in 2014.

Colorado Governor's Task Force Releases Draft Report

A task force established by Colorado Governor John Hickenlooper recently released a draft report on strategies regarding state and local development and regulation of oil and gas activities.  The task force determined that "drawing bright lines between state and local jurisdictional authority was not realistic or productive," thus refusing to find that local authority is completely preempted by the Colorado Oil & Gas Act.  The group also concluded that no new laws are necessary at this time, but that consideration of Colorado's oil and gas rules related to setbacks and air quality are topics for further discussion.  

The task force is comprised of representatives from counties, municipalities, the state, industry, civic organizations and the general public.  The Governor's task force was established only a few days after two New York trial courts rejected separate legal challenges to local zoning amendments that banned hydraulic fracturing – handing victories to those who advocate for "local" (not state) control over whether fracing is allowed.  Fracing supporters in Colorado had hoped that the task force report would conclude (or recommend) that state regulation preempted local ordinances like those in New York.  Fracing opponents had hoped for a conclusion that new and more stringent rules were required in Colorado.  The draft report's conclusions have disappointed both sides in the debate.  Stakeholders with interests in Colorado should keep a close eye on this task force as it begins issuing findings on key issues.

The final report and recommendations are available here.

California Makes A Late Entry Into Hydraulic Fracturing Regulation

California has no state laws specifically regulating hydraulic fracturing even though the process has been used for decades in the state.  That, however, is poised to change as state legislators weigh a spate of bills related to chemical disclosure rules that have been making their way through different committees this month.  Two of these bills appear to have a good chance of passing, and are briefly discussed below.

Senate Bill 1054, sponsored by Senator Fran Pavley (D - 23rd District), would require operators to notify property owners at least 20 days before hydraulic fracturing activities commence near their lands.  The bill defines property owners to include all owners or occupants of property above any underground water suitable for irrigation or domestic purposes that the well is reasonably anticipated to pierce.  That bill passed the Senate Natural Resources Committee on a party-line vote.

Assembly Bill 591, sponsored by Assemblyman Bob Wieckowski (D - 20th District),  would require operators to post fracing fluid constituents to FracFocus.org, a national registry set up by the Groundwater Protection Council and others to promote voluntary chemical disclosure.  The bill tracks similar provisions in Colorado statutes by requiring that disclosures be made within 60 days of fracing activity completion, and exempting certain trade secrets upon application by the operator.  AB 591 is due for consideration by several environmental committees before going to vote.

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by Charlotte Doerr

The practice of fracing (referred to as “fracking” in the UK) in the United Kingdom has once again come under scrutiny.  The UK’s Department of Energy and Climate Change (DECC) commissioned an independent panel to examine a possible relationship between the practice and certain earthquakes which took place in April and May 2011.  The earthquakes occured near the site of the UK's only fracing operation in Preese Hall, near Blackpool.  On April 17, 2012, the panel published its findings in a report. 

Fracing is the practice of pumping water, sand and chemicals into shale rock at a high pressure in order to extract reserves of natural gas stored within the shale rock, known as "shale gas."  The report considered the impact such a process may have on seismic activity.  The report concluded that the fracing operation (which was suspended following the earthquakes) had caused the earthquakes, thus providing some of the first evidence of this connection.  However, the report also found that the risk that fracing could cause an earthquake resulting in significant damage was "very low." 

The report recommended that fracing be allowed in the UK but, given that there is evidence of a connection between fracing and seismic activity, a number of safety provisions should be put in place to mitigate against seismic risks arising from fracing.  The safety provisions include:

• conducting a detailed assessment of the relevant area prior to fracing taking place, including: performing baseline seismic monitoring so that seismic risk of the area can be determined; using both geological and geophysical data to determine the existence of any active faults in the area; and using ground motion prediction models to consider and assess the possible impact of any earthquakes; and
• implementing a "traffic light" system with real-time monitoring of seismic activity during the fracking process.  A "red light" would be triggered by any seismic tremor meauring 0.5 local magnitude (a level lower than the size of the 2011 earthquakes) or higher.  The triggering of a red light would require the cessation of fracing and the taking of certain safety procedures including, allowing fluid to flow back to the surface.

In conjunction with the publishing of the panel's report, the DECC is inviting public comment on the recommendations made by the report until May 25, 2012.

The DECC has stated that no decision will be made as to whether fracing operations for shale gas can be resumed until all comments in response to the report have been received and considered.

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by Elizabeth P. Philpott

The Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) on April 19 to amend its regulations “to incorporate by reference the business practice standards adopted by the Wholesale Electric Quadrant of the North American Energy Standards Board (NAESB) that pertain to the measurement and verification of demand response and energy efficiency resources participating in organized wholesale electricity markets.”  The NOPR is timely, coming on the heels of several contentious disputes, including FERC enforcement actions, questioning how to measure the performance of vendors of demand response and efficiency resources.  To be considered, comments on the NOPR must be submitted to FERC 60 days after publication of the NOPR in the Federal Register.

Adoption of the NAESB standards, in FERC’s view, could improve demand response and energy efficiency resource performance, measuring methods and procedures.  FERC also expressed its hope that the NAESB standards could assist Independent System Operators (ISO) and Regional Transmission Organizations (RTO) with accounting for and crediting demand response and energy efficiency resources.

NAESB describes the proposed standards as a “framework” to develop methodologies.  The proposed demand response standards include the following changes:

• Adding a meter data reporting deadline;
• Specifying advance notification guidelines;
• Establishing a telemetry interval; and
• Tightening requirement for meter accuracy.

Through this NOPR, FERC seeks comment about whether these methodologies need to be more detailed to be useful.  FERC also seeks comment on whether ISOs and RTOs need further specific development of measurement and verification standards and if so, whether NAESB or FERC should lead this process.

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by Kimberly Brame Glasspool

The Public Utility Commission of Texas (PUCT) approved two proposals to raise system-wide energy price offer caps at an open meeting held on April 12, 2012. The proposals aim to ease growing generation resource adequacy concerns in the Electric Reliability Council of Texas (ERCOT) power market, which is one of the few major energy-only electric power markets that exist worldwide and represents about 85 percent of electric power usage in Texas.

The overarching goal of the PUCT in approving these two price cap hikes is to ensure adequate electric power supply in ERCOT as forecasts for reserve margins, or the difference between available generating capacity and expected peak system load, grow increasingly narrow. The target reserve margin for the ERCOT region is 13.75 percent. Projections from ERCOT representatives indicate that reserve margins for the remainder of 2012 may be tight but should exceed the target reserve, while reserve margins may dip below that target in 2014 (potentially around 7 percent) depending on various uncertainties, such as environmental regulations and gas prices.

Under Section 25.505 of the PUCT Electric Rules energy price offers are currently limited to $3,000 per MWh. When competitive energy price offers in ERCOT become scarce, the price of energy from certain types of services, particularly power dispatched for reliability purposes, is administratively set to the high system-wide offer cap. The first of the two recently-approved proposals raises the high system-wide offer cap to $4,500 per MWh beginning on August 1, 2012. The second of these proposals raises the high system-wide offer cap incrementally over a two-year period to $5,000 per MWh beginning on June 1, 2013, $7,000 per MWh beginning on June 1, 2014 and $9,000 per MWh beginning on June 1, 2015. 

A difference of opinion among the three-member PUCT resulted in the high system-wide offer cap increases being tentatively approved in two separate proposals. Chairwoman Donna Nelson and member Rolando Pablos approved the August 1, 2012 increase to $4,500 per MWh. PUCT member Ken Anderson argued against raising the cap this August and instead for long-term, permanent change to give market participants direction to plan, finance and build new generation. He stated that the August 1, 2012 increase won’t “make a wit’s bit of difference” in bringing mothballed generation back online this summer or encouraging long-term development of generation resources. Commission Anderson also argued such sudden action might leave market participants with insufficient time to readjust their risk strategies and might enable retail electric providers that offer fixed-rate contracts to residential customers to raise retail prices under these fixed-rate contracts to cover costs associated with the difference between the current system-wide offer cap and any higher cap approved by the PUCT. Note that Section 25.475 of the PUCT Electric Rules limits the ability of retail electric providers to increase charges during the term of fixed-rate contracts but contains an exception for changes resulting from laws that impose new or different costs on a retail electric provider that are beyond its control.

PUCT staff will conduct a public hearing for the August 2012 cap increase proposal, if requested, on May 29, 2012, and initial comments on this proposal must be submitted no later than May 29, 2012. PUCT staff will conduct a public hearing for the incremental cap increase proposal, if requested, on June 15, 2012. Initial comments on this proposal must be submitted no later than June 1, 2012. 

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by James A. Pardo and Brandon H. Barnes

The U.S. Environmental Protection Agency (EPA) released final regulations on April 17 to reduce certain emissions at hydraulically fractured wells by 95 percent.  The rule, a product of a February 2010 consent decree with WildEarth Guardians and the San Juan Citizens Alliance, adds New Source Performance Standards (NSPS) and amends existing National Emissions Standards for Hazardous Air Pollutants (NESHAPS) for the oil and gas industry.

NSPS Standards

The NSPS standards will reduce by 95 percent volatile organic compound (VOC) emissions during the completion phase of hydraulically fracturing a well.  In addition, although not a regulated substance under NSPS, the new rules have the effect of reducing fugitive methane emissions by 25 percent.  These VOC and methane emissions reductions will be attained by requiring that all newly fractured or refractured wells incorporate reduced emissions controls (RECs).  In total, EPA estimates that the rule will result in reductions of 11,000 tons of Hazardous Air Pollutants (HAPs), 190,000 tons of VOCs, and 1 million tons of methane, with a net benefit of $15 million as a result of the increased profit from captured methane sales. 

The final rule adopts several changes suggested during the public comment period, most important of which is the delayed deadline of  January 1, 2015 for requiring the use of RECs.  While REC technology currently exists, EPA recognized that the number of REC units required to meet the new regulations far exceeds those actually in existence today.  Until then, well operators or owners can achieve specified VOC reductions using flaring or other approved combustion methods. 

The final rule also modifies the definition of "well completions," limiting the REC requirement to that period when fracing operations end and flowback begins.  The requirement remains in effect until the well is either continuously flowing to the flow line or storage vessel for collection (in which case there should be no fugitive emissions) or shut in, whichever occurs first. 

In addition, EPA has exempted low-pressure wells from the REC requirement in response to comments that it is unfeasible to require RECs for low-pressure wells.  For low-pressure wells, as well as wildcat (or exploratory) and delineation wells, which are also exempted from the REC requirement, operators can continue to use flaring to achieve specified reductions.

EPA also has rewarded early adopters of REC technology, and encourages others to join early, by redefining actions that constitute "modifications" triggering NSPS requirements.  Some states require that any source subject to federal NSPS must get a state minor source air permit.  This new definition allows owners and operators of existing wells employing RECs to refracture without changing state permit status, thus avoiding delays and costs associated with the state permitting process.

Finally, but importantly, the rest of EPA's new rules are not delayed, and take effect 60 days from publication in the Federal Register.

NESHAPS Standards

While EPA adopted many of the comments about the NSPS rules, stakeholders were less successful in obtaining changes to the proposed NESHAPS standards.  In fact, EPA's final NESHAPS amendment is in some ways more strict that the rule proposed several months ago.  For example, the proposed rule revised the NESHAPS standard for glycol dehydration unit process vents and leak detection and repair requirements.  The final rule also pulls in previously-unregulated "small" glycol dehydrators.  Some gas wells using these "small" units to remove water from gas may now be subject to Maximum Available Control Technology (MACT) regulating BTEX emissions, the strictest emission controls available under the Clean Air Act.

EPA estimates that the final NESHAPS amendment will cost industry $3.5 million to implement and will remove 670 tons of HAPs, 1,200 tons of VOCs, and 420 tons of methane.

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by David Birchall and Caroline Lindsey

The UK feed-in tariff (FIT) scheme was introduced in the United Kingdom in April 2010, under the Energy Act 2008, to encourage households and businesses to operate small scale (less than 5MW) low carbon electricity generation facilities.  Under the scheme, eligible generators can receive a fixed generation tariff for each kWh of electricity generated and consumed on-site and an additional export tariff for each kWh of electricity that is exported to the grid, for a maximum of 25 years from the date an installation becomes eligible under the scheme.  FIT payments are paid to generators by suppliers and funded by electricity consumers.

Of the eligible technologies (biogas, hydro, micro-CHP and solar photovoltaic (PV)), solar PV has to date been by far the most popular technology.

To read the full article, click here.

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by James A. Pardo and Brandon H. Barnes

Western Maryland sits atop the Marcellus Shale and, since approximately 2008, several companies have leased lands in anticipation of conducting hydraulic fracturing (fracing) operations in the area.  Those operations have been on hold since March 2011 because of a de facto moratorium on fracing that Governor O'Malley and the Legislature put in place to give officials time to complete a two-year study of potential environmental and health impacts, and to propose rules for how fracing operations in the state should be conducted.  That study is due to be completed in 2013, but in the interim Maryland legislators have proposed almost 20 bills aimed at fracing activity in the State.  Stakeholders should be aware of recent actions taken on two of these legislative proposals.

First, $1 milion reportedly is required to finish the  administration’s study, and funding has not been provided for in this year's state budget.  To close this funding gap, Governor O'Malley recently proposed legislation that would have imposed a one-year fee of $10.00 (Senate version) or $15.00 (House version) per acre on all lands already leased in western Maryland for potential fracing activity.  After the General Assembly rejected that fee legislation, Governor O'Malley announced that his administration will complete the study with funds from other (yet undisclosed) sources.  The issue for stakeholders is that, the lack of funds may delay the study’s completion -- meaning that Maryland stakeholders may have to wait until 2014, or longer, to see if fracing will be allowed and under what rules.  

Indeed, whether fracing takes place at all may be the next battle in Maryland.  Representative Heather Mizeur (D-Montgomery County), who introduced the fee legislation in the Maryland House, has warned that she may now seek a permanent ban on fracing in light of industry's opposition to the fee bill.  Fracing stakeholders with an existing (or potential) interest in Maryland may want to keep an eye on Annapolis in the coming months before committing resources to the Old Line State.

Second, on April 6, the Maryland General Assembly passed another of Rep. Mizeur's legislative initiatives, a bill that creates a "presumptive impact area" around a well that has been hydraulically fractured.  Under this new rule, well operators will be presumed responsible for any contamination that occurs within 2,500 of a well for one year after the last operational activity on that well.  The operator will bear the burden of proving that any such contamination was not caused by its fracing operations.  If this burden cannot be met, the operator will be required to install a new water supply well (or retrofit the existing supply well) for anyone impacted by the contamination.  Burden-shifting rules exist in several states for contamination caused by leaking underground storage tanks, and legislation similar to Maryland's also has been proposed in New York.  Because such rules make it easier for property owners to sue for alleged impacts to their private water supplies, they may encourage litigation – something fracing stakeholders may want to take into account before setting up shop in Maryland.

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by James A. Pardo and Brandon H. Barnes

The link between hydraulic fracturing activity and seismic activity has been the subject of much discussion of late, including on this blog (see "USGS Study Concludes Increased Seismicity May Be Attributable to Hydraulic Fracturing," posted on April 4, 2012).  Ohio has put in place new rules for deep-well injection disposal of used fracing water, in an attempt to avoid the small earthquakes that occurred in Youngstown last Fall.  New York is now weighing in on the issue.  State Senator Tony Avella recently introduced a bill  that would require a seismological impact study related to hydrofracking to be performed by a state university.  Sen. Avella's bill would require that the study consider potential seismic effects both locally and state-wide; that it recommend activities or practices to mitigate future seismic activity; and that it provide a plan to monitor for seismic activity in the future. 

The bill proposes to fund the study through appropriations from the general budget, which was the death-knell for a similar piece of legislation introduced earlier this year that would have funded a state university study of fracing's health effects.  Given New York's tight fiscal environment, and the fact that federal studies of a possible fracing-earthquake link are already underway, we expect this bill to meet the same fate as the health study.  Sen. Avella, fully aware of the fate of the heath study bill (which he sponsored) likely is making a political statement with this latest legislation.  Nevertheless, stakeholders need to be aware that the earthquake-fracing link is one that is catching increased attention from federal and state authorities, and likely will remain an issue for some time.

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by James A. Pardo and Brandon H. Barnes

At the request of residents in Dimock, PA, for the past several months EPA has been testing drinking water wells for contamination that the residents attribute to nearby fracing activities by Cabot Oil.  Earlier this month EPA concluded that the water in several of these wells was safe to drink.  Last Monday, EPA reported that the water in several other wells also was safe to drink.

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by Bethany K. Hatef

The Department of Energy (DOE) announced that it has $15 million available to award for the development and demonstration of biomass-based oil supplements, or bio-oils.  The grants will go toward research and development projects aimed at speeding the development of thermochemical liquefaction technologies to produce bio-oil feedstock from high-impact feedstock biomass or algal biomass.  Successfully produced bio-oils could then be blended with petroleum to produce transportation fuels, including gasoline, diesel, and jet fuels, without significantly modifying oil refining processes for conventional transportation fuels, existing fuel distribution networks, or engines.

DOE explained in the early April announcement that it expects to fund five to ten projects in 2012.  The projects will aim to produce bio-oil prototypes that can be used for testing in refineries and for research and development of bio-oil technologies and renewable fuels produced from bio-oils.  Projects may propose technologies using bio-oil produced from a variety of feedstocks, including algae, corn and wheat stovers, dedicated energy crops, or wood residues.

Projects must produce bio-oils using: (1) high-impact feedstocks with an agronomically and ecologically sustainable potential of at least 50 million dry tons per year in the United States, or (2) oils extracted from algae, if that algae is grown using a high-impact cellulosic biomass feedstock.  Grant eligible projects must propose bio-oils that can be used at one or more insertion points within an oil refinery, defined as any point after vacuum or atmospheric distillation where a feedstock may be inserted for further processing. Any American company, university, or laboratory may apply for a grant, which will be between $400,000 and $4 million each.

The DOE’s investments in renewable transportation fuels, explained Energy Secretary Steven Chu, are a “key part” of President Obama’s plan “to develop America’s domestic energy resources and reduce our nation’s dependence on foreign oil.” DOE’s biofuels grant announcement comes on the heels of another announcement that the DOE would revitalize its expired loan guarantee program for solar, wind, and geothermal energy projects by setting aside $170 million of its congressionally approved funds for such projects.

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