Environmental Law ReSource

Record Highs and Lows in New Jersey's Uncertain Solar Market

David Wagner — Thu, 10 May 2012 13:23:31 -0500

This post was written by Jim McGuire, Henry King, Ferd Convery, and Marshall McLean

The New Jersey solar SREC market is significantly over-supplied. The renewable portfolio standards (“RPS”) for Energy Year (“EY”) 2012 (June 1, 2011-May 31, 2012) requires that a total of 368 MWs in solar generation capacity be installed by May 31, 2012. That requirement was satisfied in June 2011, only one month into EY 2012. BPU staff estimates that installed solar capacity will exceed the solar RPS through at least energy year 2014 and, depending on the near-term installation rate; the solar capacity may exceed New Jersey solar RPS through EY 2016. As noted by BPU staff in its solar transition straw proposal the pace of construction, installation and operations in the New Jersey solar market is not sustainable within the current solar RPS.

This week legislation (S-1925) was introduced by Senators Smith and Sweeney which proposes long awaited relief to the New Jersey solar market. The bill, which is not yet publicly available, is expected to be scheduled for hearings before the Senate Energy and Environment Committee chaired by Senator Smith on an expedited basis. S-1925 will likely seek to regain lost momentum in New Jersey’s solar market by focusing on: revised RPS and solar alternative compliance payment ("SACPs") schedules, preference for location of solar facilities on brownfields and landfills rather than on farmland, grid connected projects, net metering requirements including clarification of what it means to be connected to the distribution system, and an aggregated net metering program for local government and school districts.

In this client alert, we discuss the proposed legislative remedy as well as regulatory remedies. For additional information please contact one of the authors listed above.

Minard Run Litigation Continues With a Small Victory for the U.S. Forest Service

David Wagner — Wed, 09 May 2012 16:32:19 -0500

This post was written by Nicolle Bagnell and Lucas Liben

On March 23, a Pennsylvania federal district court denied a motion by drilling operators to hold the U.S. Forest Service in contempt of the court’s 2009 ruling that requires the Forest Service to process oil and gas lease development proposals in accordance with that ruling. See Minard Run Oil Co. v. U.S. Forest Service, 2012 WL 994641 (W.D. Pa. Mar. 23, 2012). The court noted that although “there is some evidence to suggest that delay has replaced diligence as the hallmark of the Forest Service’s processing of drilling proposals,” there was not “clear and convincing evidence” sufficient to find the U.S. Forest service in contempt for these activities.

Here’s some background: Federal litigation regarding oil and gas drilling in Pennsylvania’s Allegheny National Forest dates back to a 1980 decision that mineral rights owners in the forest had the right to enter the property and access the minerals, but must provide the U.S. Forest Service with certain information at least 60 days prior to doing so. In a 2009 settlement with an environmental organization, the Forest Service revised its policy and agreed to perform environmental analyses before drilling could go forward. Owners of mineral rights sued the Forest Service and a federal court granted a preliminary injunction against the policy on the basis that they had been denied access to their holdings. In 2009, the U.S. Third Circuit Court of Appeals upheld the injunction, ruling that the Forest Service policy had the effect of causing severe economic hardship to the plaintiffs.

U.S. Department of Interior Releases Draft Rule on Public Disclosure of Chemicals Used in Hydraulic Fracturing on Public and Indian Lands

David Wagner — Mon, 07 May 2012 15:00:00 -0500

This post was written by David Wagner

A few months ago, our blog previewed this year's top 10 environmental legal issues related to shale gas. Late last week, there were developments in two of them. On May 4, the U. S. Department of the Interior (DOI) released its proposed rule to require companies to publicly disclose the chemicals used in hydraulic fracturing operations on public and Indian lands. The proposed rule, from DOI’s Bureau of Land Management (BLM), will soon be published in the Federal Register. At that point, a 60-day public comment period will begin, during which the public, governments, industry and other stakeholders can provide their input.

The proposal identifies requirements for extensive information filings prior to drilling and reporting of what was done after the fracturing. For example, the proposed rule would require BLM’s approval of all well stimulation activity. In addition, an operator would be required to submit a drilling plan, including elements such as a detailed description of the well stimulation engineering design for BLM approval.

An operator would also have to submit the estimated or calculated fracture length and height anticipated as a result of the stimulation. The actual total volume of fluid used would have to be reported after the fracturing was performed. Further, the operator would have to report the actual handling and disposal of recovered fluids.

The information obtained by BLM is intended to be posted on a public web site, and BLM is working with the Ground Water Protection Council to determine whether the disclosure can be integrated into website FracFocus.org.

USEPA's Draft Guidance for Diesel Fuel in Hydraulic Fracturing Clarifies Compliance with Safe Drinking Water Act

David Wagner — Mon, 07 May 2012 14:43:29 -0500

This post was written by Jennifer Smokelin

Here's another environmental legal development we previewed at the beginning of the year. In 2005, Congress exempted hydraulic fracturing from requirements to obtain an underground injection permit under the Safe Drinking Water Act (SDWA), but still required a permit when diesel fuel is used as a fracturing fluid. On May 4, the U.S. Environmental Protection Agency (USEPA) published draft guidance for SDWA permits issued to oil and gas companies that use diesel fuels during hydraulic fracturing. The draft guidance outlines requirements for diesel fuels used for hydraulic fracturing wells, technical recommendations for permitting these wells, and a description of diesel fuels for USEPA underground injection control permitting. Note that the draft guidance only applies to USEPA permit writers and where USEPA is the permitting authority, The draft guidance includes six categories of fuels (based on CAS abstract numbers) deemed to be considered diesel, while stopping short of an outright ban on the use of the fuel. If these categories of fuels are being used, drillers will need to apply for a specific permit and this could delay drilling. The guidance does not address possible liability for companies that used diesel fuel in the past to fracture rock formations to free trapped natural gas.

USEPA will take public comment on the draft guidance for 60 days upon publication in the Federal Register to allow for stakeholder input before it is finalized.

"Best Practices" Guidance Released for Marcellus Shale Operators

David Wagner — Thu, 03 May 2012 15:39:55 -0500

This post was written by Jennifer Smokelin

In order to reduce liability for natural gas development, it is a given that companies "know the rules and make sure you comply with them." A corollary to this maxim is that companies understand the industry's "best practices" and strive to follow them. For hydraulic fracturing, the American Petroleum Institute had issued industry guidance/best practices on hydraulic fracturing and, a few days ago, the Marcellus Shale Coalition (MSC) released its first recommended practices (RP) that offers guidance on site planning, development and restoration. The RP will assist industry professionals operating in the Appalachian basin in improving their effectiveness in the site planning, development and restoration aspects of responsible natural gas exploration and production. The RP was developed by the MSC’s Land Affairs Committee and it set forth 11 steps in the site preparation, development and restoration process for natural gas development, beginning with identifying the need for a new well site, compressor station or pipeline, and ending with site monitoring, maintenance and repair. The guidance document is the first of many that MSC is expected to release in the coming months, and the additional guidance is expected to cover topics from well construction to air quality and water management.

Slides and Audio from Reed Smith's Teleseminar on Shale Gas

David Wagner — Thu, 26 Apr 2012 11:02:57 -0500

This post was written by David Wagner

With all of the recent attention given to shale gas, we featured the issue in our quarterly Environmental and Energy Teleseminar. Here are the slides and audio from yesterday’s event. In particular, we discussed:

Recent developments related to aggregation and U.S. Environmental Protection Agency’s new air emission rules for the oil and gas industry
Hydraulic fracturing and chemical disclosure requirements, especially in state jurisdictions
Overview of fracking regulations and developments on federal level
Pending shale gas legislation in California
Overview of international shale plays

Look for our next quarterly teleseminar this summer.

USEPA's New Air Emission Rules for Oil and Gas Industry Address Some Industry Concerns but Raise Others

David Wagner — Tue, 24 Apr 2012 17:56:40 -0500

This post was written by Jennifer Smokelin

On April 17, the U.S. Environmental Protection Agency (EPA) promulgated the first-ever final regulation setting limits on air pollution from natural gas production aimed at reducing toxic air pollution from the natural-gas drilling process called fracking. EPA updated its New Source Performance Standards (NSPSs) and National Emission Standards for Hazardous Air Pollutants (NESHAPs) to include emissions from oil and gas production. The new standards will reduce the amount of methane, volatile organic compounds, and other emissions coming from fracking operations by requiring that all newly fractured or refractured wells incorporate reduced emissions controls (RECs). The regulations will also target emissions from compressors, oil storage tanks and other oil-and-gas sector equipment.

The biggest news is that, under the final rules, EPA delayed the deadline for requiring the use of RECs or “green completions”. In its proposed rule, “green completions” were required 60 days after final publication of the rule in the Federal Register. Now, under the final rule, well operator and owners have until January 1, 2015 before they need to conduct green completions. Between now and 2015, compliance with the rules can be achieved via reductions using flaring or other approved combustion methods, although early adoption of green completion is "encouraged".

In addition, there are a few other exemptions from compliance under the final rules. For example, wells drilled in low-pressure areas, such as coal-bed methane reserves, are exempt because these wells release less pollution during completion. And companies that choose to re-fracture wells using the pollution-reducing equipment prior to the January 2015 deadline would not be covered by the NSPS. These are significant changes from the rule as proposed in July 2011.

Despite these changes, industry still remains concerned about federal regulation of the oil and gas industry, including issues of “regulation overlap” (that is, where one federal agency will require one thing while another federal agency will regulate the industry another way). As we reported on the blog last week, President Obama announced the formation of a high-level task force last week charged with coordinating oversight of fracking in an effort to reassure industry groups that are concerned about overlapping federal regulations. Of course, it remains to be seen whether this will be successful.

DECC Publishes Report Advising UK Government on Hydraulic Fracturing

David Wagner — Tue, 17 Apr 2012 15:28:56 -0500

This post was written by Lynne Freeman and Laura Riddeck

A report commissioned by the Department of Energy and Climate Change (DECC) advising the UK Government that the controversial process of hydraulic fracturing, or “fracking”, should be allowed to continue, was published today. This is likely to thrust the process back into the spotlight, with Cuadrilla Resources Ltd likely to resume its activities and other companies to look to get a piece of shale gas action.

Background

Cuadrilla Resources Ltd began using fracking to explore sites for shale gas in Lancashire, north England, in March 2011.In April and May 2011, however, two seismic tremors were detected in the Blackpool region. These were immediately suspected to be linked to fracking processes in wells operated by Cuadrilla during exploration of a shale gas reservoir. As a result of the tremors, operations were suspended and Cuadrilla commissioned a number of studies examining the relationship between the fracking operations and the seismic activity.

Findings & Recommendations

Cuadrilla’s report, published in November 2011, found that:

The seismic activity was caused by direct fluid injection into an adjacent fault zone during the treatments. The fluid injection reduced the normal stress on the fault, causing it to fail repeatedly in a series of small earthquakes. The fault location, however, was not identified.
The maximum likely magnitude resulting from a similar treatment is estimated as 3.0 ML. An event of this size is not expected to present a significant hazard.
There is a very low probability of other seismic events during future treatments of other wells.
The potential for upward fluid migration was considered low. In the worst case, fluid could migrate along the fault plane, but this would be limited due to the presence of impermeable formations along the Bowland shale.

Subsequently, the DECC commissioned a further report to review these findings and advise the government on the risks posed by fracking. The report agreed with the main conclusions of Cuadrilla’s study regarding the nature and mechanism of seismic activity, but had two concerns:

The probability of future seismic tremors: The report considered that there is not enough data to justify from a simple statistical analysis of the geomechanical situation that there is a low probability of encountering a similarly unique scenario in any future wells; and
The potential for upward fluid migration: The DECC considered that this was overstated in the initial studies, based on micro-seismic shale gas data from the main US plays. Further analysis seems to indicate that fracture containment was good, with little vertical height growth. However, the DECC report states that it is difficult to reach any concrete conclusions without confirmatory information from fracture diagnostics.

This long awaited report concludes that the risks posed by fracking are relatively small and that the use of fracking in shale gas exploration should be allowed to resume. However, the DECC have advised that several precautions should be adopted in order to mitigate the risks posed by fracking:

The fracking procedure should invariably include a smaller pre-injection and monitoring stage before the main injection;
Fracking growth and direction should be monitored during future treatments;
Future fracking operations in this area should be subject to an effective monitoring system that can provide automatic locations and magnitudes of any seismic events in near real-time; and
Operations should be halted and remedial action instituted if events of magnitude 0.5 ML or above are detected.

The report also published a best practice guide for fracking operations which is based primarily on experience in the US. This guide can be found at Appendix B of the report.

Reaction & Next Steps

Mark Miller, Cuadrilla's chief executive, welcomed the report and was quoted as saying: “We are pleased that the experts have come to a clear conclusion that it is safe to allow us to resume hydraulic fracturing, following the procedures outlined in the review.” He said that Cuadrilla had already begun to amend procedures in light of expert advice.

However, implementing these recommendations is likely to add significantly to the cost of drilling operations. Some experts estimate it could be more than £100,000; others have suggested it could be many times that for each well. This may have a bearing.

The report is now open for a six week consultation period, with the DECC issuing a firm set of regulations after that. It seems likely that the government will follow the DECC’s recommendations in the report, and Cuadrilla will be able to resume its exploration in Lancashire in a matter of months.

President Obama Intends to Strengthen Federal Oversight of Hydraulic Fracturing Process

David Wagner — Tue, 17 Apr 2012 14:07:30 -0500

This post was written by Christopher Rissetto and Ariel Nieland

On April 13, the White House released an Executive Order calling for the creation of an "Interagency Working Group" (Working Group) charged with "overseeing the safe and responsible development of unconventional domestic natural gas resources." The Order defines the functions of the Working Group to include: (i) coordination of agency policy activities; (ii) coordination of the sharing of scientific, environmental, and technical and economic information; (iii) engagement in long-term planning with respect to research, natural resource assessment, and infrastructure development; (iv) promotion of interagency communications with outside stakeholders; and (v) consultation with other agencies and offices. The Working Group will be comprised of members from 13 different high-level agencies and departments, including, among others, the Department of Defense, the Environmental Protection Agency, the Department of Energy, the Department of Transportation, and the Department of Homeland Security.

The Order was issued approximately two months after the American Petroleum Institute requested that the Administration designate an agency to take the lead in coordinating federal policy and regulation efforts with regard to unconventional oil and gas. According to news reports, the unconventional gas policy group will be led by President Obama's top energy and climate advisor, Heather Zichal.

The Administration's efforts precede issuance of rulemakings by the Bureau of Land Management and the Environmental Protection Agency that will also impact oil and natural gas production.

Water Quality OK in USEPA Report on Wells in Dimock, Pennsylvania

David Wagner — Mon, 16 Apr 2012 12:13:14 -0500

This post was written by Nicolle Bagnell and Ariel Nieland

In 2010, according to the Pennsylvania Department of Environmental Protection (DEP), natural gas drilling activities in Dimock, Pennsylvania were believed to be the source of gas migration and water contamination problems allegedly affecting residents' water wells. Since then, the U.S. Environmental Protection Agency (USEPA) has been investigating and now reports that about 31 of the water wells tested so far do not have dangerous levels of contamination. Last week, USEPA published the results of additional tests conducted on approximately 20 water wells in Dimock, which showed that the water underlying those homes contained no elevated levels of contamination. These results supported USEPA's similar findings from last month regarding tests from 11 other residential water wells in the area. USEPA began testing water wells in January of 2012 for 61 homes within a 9-square-mile radius of Dimock and will continue to publish results from those tests as they become available.

Local Zoning Laws Remain in Place for the Pennsylvania Oil and Gas Industry - For Now

David Wagner — Thu, 12 Apr 2012 11:19:29 -0500

This post was written by Nicolle Bagnell and Luke Liben

When Pennsylvania’s new Marcellus Shale drilling law (known as Act 13) goes into effect on April 14, the section that preempts local drilling ordinances will be temporarily put on hold. Although Act 13 specifically overrides local zoning laws related to oil and gas operations, yesterday the Pennsylvania Commonwealth Court granted an injunction of the enactment of all provisions addressing the state’s preemption of oil and gas zoning laws. In the matter Robinson Township, Washington County, Pennsylvania v. Commonwealth of Pennsylvania, No. 284 M.D. 2012, the court issued a 120-day injunction that will extend the time period that municipalities have to craft new ordinances to comply with Act 13. The plaintiffs in the case, mostly municipal officials and two individuals, stated that the injunction was necessary to avoid any uncertainty that would otherwise arise in this 120-day period. No other aspects of Act 13 will be affected by the injunction.

Great Lakes Offshore Wind Power MOU to Facilitate Evaluation of Proposed Projects and Expedite Permitting

David Wagner — Tue, 10 Apr 2012 14:59:25 -0500

This post was written by Robert Vilter, Amy Koch, Stefan Schmitz, and Patrick Elder

On March 30, 2012, ten federal agencies and the governors of Illinois, Michigan, Minnesota, New York and Pennsylvania signed a new memorandum of understanding (MOU) to develop a roadmap within 15 months that would describe the regulatory review process and data needed to “inform efficient review” of proposed offshore facilities in the Great Lakes. The MOU is designed to speed review of proposed offshore wind projects by increasing collaboration between federal and state agencies.

According to the U.S. Department of Energy, the Great Lakes' region is home to the largest offshore wind potential of any U.S. waters – 742.5 GW, or one-fifth of all potential wind energy in the United States. Each gigawatt of offshore wind power installed could produce electricity for 300,000 homes.

The MOU will not eliminate any of the myriad federal and state approvals needed to construct and operate an offshore wind project in the Great Lakes, but may ultimately result in one or more roadmaps that could be of real assistance to developers. In this client alert, we discuss some of the interest and opposition to offshore wind development in the region.

Spotlight on Shale Gas: Join Us for Reed Smith's Environmental and Energy Law Resource Teleseminar on April 25

David Wagner — Thu, 05 Apr 2012 14:54:51 -0500

On April 25, 2012, Reed Smith will focus on environmental issues related to shale gas during its quarterly teleseminar. This free teleseminar will be held from Noon to 1 pm ET.

Topics include:

Air pollution aggregation update and status of NSPS fracturing regulation
Fracking disclosure: Pennsylvania's new Act 13 and other jurisdictions
Overview of federal fracking regulations
Pending shale gas legislation in California
Overview of international shale plays

The speakers at this event will be: Larry Demase (Pittsburgh), Lynne Freeman (London), Todd Maiden (San Francisco), Jennifer Smokelin (Pittsburgh), and David Wagner (Pittsburgh). To read more about our speakers, please click the attorney's name.

TO REGISTER: Please click here.

USEPA Withdraws Range Resources' Imminent and Substantial Endangerment Order in Fifth Circuit

David Wagner — Tue, 03 Apr 2012 11:16:12 -0500

This post was written by Jennifer Smokelin

As we've discussed on the blog, in late 2010, homeowners who lived near drilling operations of Range Resources in Parker County, Texas, reported problems with their tap water, complaining that it was bubbling and even flammable. On December 7, 2010, the U.S. Environmental Protection Agency (USEPA) issued an emergency order under the Safe Drinking Water Act to the company to take immediate action to protect the homeowners. Range Resources protested the order and the case was hard fought for over a year. In short, Range Resources argued that it was entitled to pre-enforcement review and that USEPA is obligated to show facts supporting the underlying elements of the violation in court to secure injunctive relief and impose civil penalties. A few days ago, USEPA withdrew the order, according to documents filed last week in the U.S. District Court of the Northern District of Texas.

USEPA's surprise withdrawal came less than a week after the unanimous U.S. Supreme Court decision is Sackett v. United States Environmental Protection Agency, et al., (Case 10-1062) (Sackett). In Sackett, the U.S. Supreme Court held that USEPA's order under the Clean Water Act directing a homeowner to remove fill material from an area that USEPA alleged included regulated wetlands was final, ripe, and immediately reviewable. We connected the dots and discussed that, while Sackett was decided under a different statute (the Clean Water Act), there were implications in Sackett to the Range Resources case under the Safe Drinking Water Act. Even though USEPA's documents withdrawing the order in the Range Resources case do not rely on Sackett expressly, one can surmise based on the breadth of the Sackett opinion and the analysis previously provided in this blog that the holding in Sackett had at least something (if not everything) to do with it. Drawing from these recent events, recipients of any USEPA administrative enforcement order have increased incentives to carefully analyze their options about challenging the order prior to enforcement.

Pennsylvania Issues New General Permit for Oil and Gas Wastewaters

David Wagner — Tue, 27 Mar 2012 14:13:53 -0500

This post was written by Mark Mustian

On March 24, the Pennsylvania Department of Environmental Protection (DEP) revised and reissued General Permit WMGR123, which authorizes the processing and beneficial use of processed liquid wastes generated on oil and gas well sites and associated infrastructure. WMGR123, issued under the authority of the Bureau of Waste Management, replaces the three existing general permits which previously regulated the recycling and reuse of oil and gas wastewaters.

Wastewater generated from well sites that is sent off-site for reuse is regulated as a residual waste, and requires permitting by DEP's Solid Waste Group. Prior to the issuance of the new general permit, there were 3 different general permits applicable to oil and gas operations: WMGR119, WMGR121, and WMGR123. The required permit was based upon the source of the water, the type of treatment, and the use of the recycled water, but the permits were generally very similar. WMGR119 and 121 are now revoked and all off-site activities will be authorized under the new WMGR123 permit. In addition, the on-site reuse of drilling wastes has previously been authorized by the Oil and Gas Program through submittal of Form 5500-PM-OG0071. There is no indication that this procedure has changed, but it is a question that will need to be answered.

The new general permit removes some current restrictions on the recycling of oil and gas wastewaters, and also adds some new requirements. For facilities that plan to recycle and reuse relatively dilute waters, the new permit should be helpful. In particular, for wastewaters with low total dissolved solids (TDS) (i.e., less than 500 mg/l) that are in compliance with standards found in Appendix A of the permit, the operator will not have to manage the waste as a residual waste, and should be able to utilize existing designs for impoundments and handling of the water. This approach would work for water generated at a well site and stored prior to transport to a recycling facility, and for recycled water which has been treated and transported to a well site for reuse. These wastewaters with low TDS will no longer have to be transported as a residual waste.

However, for high TDS wastewater which does not comply with the Appendix A standards, both the generators and users of the recycled water will potentially have new compliance standards. Until the processed oil and gas liquid waste has been transported to a well site and is actually used to develop a well, it must be managed as a residual waste. From the language of the permit, it appears that the requirement to manage the wastewater as a residual waste would apply to both the operator generating the waste and the operator reusing the waste. This will require the operators at both sites to comply with the regulations on storage and transportation found at 25 Pa Code § 299, and in particular the permitting and design requirements for impoundments found in Section 299.141 through 299.145. If either the generator of the waste, or the party beneficially reusing the waste wishes to store the waste prior to either shipment or reuse, they will need to comply with storage requirements that are generally more stringent than the requirements under the oil and gas regulations.

Moreover, the permit holder must comply with several other requirements associated with the general permit. They include: a bonding requirement; sampling requirements to determine whether the wastewaters comply with the Appendix A standards; facility siting requirements; and inspection and records requirements. Overall, the new general permit appears to be designed for permanent recycling facilities that are receiving water from various drill sites, processing it, and then sending it out for reuse at other sites. It does not appear that the general permit will work effectively for individual well sites that want to just transport their water to another well site for reuse.

Sailing across the Yard - Supreme Court Corrects EPA Compliance Reviewability

David Wagner — Fri, 23 Mar 2012 15:27:00 -0500

This post was written by Christopher Rissetto and Jennifer Smokelin

A unanimous U.S. Supreme Court recently held that the U.S. Environmental Protection Agency’s order directing a homeowner to remove fill material from an area that EPA alleged included regulated wetlands was final, ripe, and immediately reviewable under the Administrative Procedure Act (APA). In this blog post, we provide some background, discuss the issue of finality under the APA, and consider some implications of this decision, especially with respect to the Safe Drinking Water Act.

Mike and Santell Sackett were surprised when the U.S. Environmental Protection Agency (USEPA) and the Army Corps of Engineers interrupted their initial efforts to build a home near an Idaho lake. The Sacketts had begun to place dirt and gravel fill on their newly purchased property, when USEPA issued a Compliance Order. The Order directed the couple to stop construction and restore “wetlands” that were determined to exist on the property, and claimed that their actions in placing fill in a wetland was a violation of the Clean Water Act (CWA), with the possibility of up to $75,000 per day in potential liability.

The Sacketts unsuccessfully sought review of the USEPA compliance order on the basis that they were not subject to the jurisdiction of the Agency, as the property did not contain regulated wetlands. However, USEPA argued that the Sacketts had no right to any review of the issue until EPA brought an enforcement proceeding against them. The U.S. District Court agreed and this decision was affirmed by the Ninth Circuit Court of Appeals, which held that there could be no CWA pre-enforcement review. On March 21, 2012, the U.S. Supreme Court ruled 9-0 against USEPA, reversing the lower courts and holding that USEPA’s Compliance Order was a final agency action and therefore could be reviewed under the Administrative Procedure Act (APA), even if the CWA did not expressly provide such a right of appeal. See Sackett v. United States Environmental Protection Agency, et al., Case 10-1062 (Sackett). The holding in Sackett was direct and unequivocal. Yet the concurring opinion by Justice Alito perhaps best expressed the Court’s true concerns, as Judge Alito observed that: “The position taken . . . by the Federal Government – a position that the Court now squarely rejects – would have put the property rights of ordinary Americans entirely at the mercy of [USEPA] employees.”

Now, parties adversely affected by USEPA compliance orders (and perhaps orders from other federal agencies) may have an alternative path to judicial review under the APA. Federal agencies will likely consider their Compliance Order authority in a new light, as it no longer can be used to advance agency interests without the possibility of further scrutiny.

Language similar to the CWA enforcement order language can be found in several other federal environmental statutes, including the Comprehensive Environmental Response, Liability, and Compensation Act (CERCLA), the Clean Air Act, the Resource Conservation and Recovery Act (RCRA) and the Safe Drinking Water Act (SDWA). It should be noted there are differences between the CWA and these other laws, which could distinguish them from Sackett. For example, unlike the CWA, CERCLA contains an explicit provision barring pre-enforcement review of a USEPA cleanup order. This provision was challenged last year and the Supreme Court refused to take the case. Look for another challenge of a USEPA cleanup order under CERCLA to test whether the APA’s presumption of reviewability trumps CERCLA’s non-enforcement provision.

In a federal district court suit in the Fifth Circuit where USEPA is seeking an injunction to force a gas drilling company, Range Resources, to comply with a Safe Drinking Water Act (SDWA) emergency order, Range Resources is arguing to the Fifth Circuit that it was entitled to pre-enforcement review and that USEPA is obligated to show facts supporting the underlying elements of the violation in court to secure injunctive relief and impose civil penalties. USEPA will likely deny that Sackett will have any effect on the Range Resources case, citing differences between the CWA and the SDWA.

However, the language in Sackett can arguably be read very broadly and is not limited just to the CWA. There is some broad language on the issue of whether a compliance order is a “final agency action” subject to judicial review. Writing for the majority, Justice Scalia states“[t]here is no doubt [the compliance order] is agency action” and further, “[i]t has all the hallmarks of APA finality that our opinions establish.” Admittedly, Justice Scalia held that the key to the case was the fact that the Clean Water Act does not, as the government claimed, preclude judicial review under the Administrative Procedure Act. However, assuming other environmental statutes similarly do not preclude review under the APA, the opinion leaves open the argument that if the core hallmarks of “final agency action” can be established with regard to an enforcement order under another statute, so too would agency action under that other statute be subject to pre-enforcement review.

Time will tell whether the Fifth Circuit will broadly read Sackett to apply to pre-enforcement review under the SDWA - or indeed whether other courts will apply Sackett to statutes other than the CWA, or other federal agencies besides USEPA. For now, parties adversely affected by federal agency compliance orders should seek legal counsel to determine if there may be an alternative avenue to obtain pre-enforcement review of that order.

Next Steps in New Jersey's Solar Transition

David Wagner — Thu, 15 Mar 2012 14:45:43 -0500

This post was written by Jim McGuire, Henry King, Ferd Convery and Marshall McLean

The New Jersey Board of Public Utilities (BPU) will hold a Public Hearing on March 22, 2012 starting at 9:30 am at its Trenton Office, 44 South Clinton Avenue. The purpose of the Public Hearing is to provide an opportunity for further public comment on a BPU Staff Straw Proposal on the next steps in the transition of NJ's Solar Program including: extension of the solar renewable energy credit (SREC) financing program administered by the four electric distribution companies (EDCs) located in the state; and related changes to the Solar Renewable Portfolio Standards (RPS). Initial Comments are due, in writing, by close of business on Friday, March 16 with final comments due at the close of the Public Hearing on March 22.

The BPU directed its staff to develop options and recommendations for next steps in response to rapid expansion of its Solar Program. The Solar Program expanded from an initial goal of 90 MW of installed solar during the five year period from 2003- 2008 to installation of more than 80 MWs in a single month during January 2012. As a result of this rapid expansion, New Jersey is projected to have an excess supply of installed solar capacity through at least energy year (EY) 2014 and perhaps through EY 2016. This excess supply has resulted in a dramatic drop in SREC prices from more than $600 per SREC in the spot market during the Summer of 2011, to about $200, and with the most recent EDC Auction in February 2012 yielding a price of $170.

The Governor's 2011 Energy Master Plan for New Jersey, which was released in December 2011, set policy goals for BPU solar program including:

support for extension of the EDC SREC Financing Program and acceleration of the solar RPS in the near term;
promote solar on brown fields and landfills;
no subsidies for solar on productive/preserved farmland or open space;
lower the costs of the SREC program while maximizing the economic and environmental benefits of solar.

Within these policy goals, BPU Staff focused on extension of the EDC SREC Programs with a near term bump in the solar RPS schedule.

The Staff Straw Proposal for the EDC SREC Program would extend program for a three year period through a competitive loan and/or solicitation program. New projects selected for funding through the EDC SREC Program would be subject to the following proposed elements:

Program Size: 120 MWs allocated proportionately among the four EDCs.
Funding Time Frame: for year one of the EDC SREC program funding would be for 10 years. For years two and three of the program funding would be for shorter time frames.
No Floor Price for SRECs but rather would seek the lowest costs within each market segment.
Costs: incurred by the EDCs for administering the SREC Programs born by the solar developer or generation customer.
Eligibility: Net Metered projects with size limited by customer on-site usage pursuant to the Net Metering Rules set forth in N.J.A.C. 14:8-4 et. seq.
Set Asides: for residential and small commercial; grid connected landfill and brown field projects in areas that can be supported by the distribution system.
Sale of SRECs: via centralized auction in EY 2016 timed to minimize market impact.

The Staff Straw Proposal for the RPS, which requires a Rulemaking, proposes:

RPS Acceleration: the additional capacity of the extended EDC SREC Program to be reflected in the solar RPS Rule Amendment effective EY 2016.
SREC Life for New Projects: SREC qualification life for new projects to be reduced from 15 years to 10 years upon effective date set per rule and with a decreasing trend thereafter through EY 2027.
SACPs: develop a revised Solar Alternative Compliance Payment (SACP) schedule for EY 2017 to EY 2026 which reflects the lower cost of solar installation.

Reed Smith Attorneys from the Princeton, New Jersey Office will monitor the Solar Transition Action Steps under consideration by the NJ BPU. For further information please contact Jim McGuire, Henry King, Ferd Convery or Marshall McLean.

U.S. Army Looking for $7 Billion in Renewable Energy Over the Next 10 Years

David Wagner — Tue, 13 Mar 2012 12:22:29 -0500

This post was written by Amy Koch and Lorraine Campos

The U.S. Army began its long-awaited process for signing up to $7 billion in renewable energy power purchase agreements (PPAs) over the next ten years. On February 24, 2012, the Army Energy Initiatives Task Force (AEITF) issued a notice seeking comment on a draft request for proposals (Draft RFP). The Draft RFP sets out the AEITF’s proposed process for signing 30-year power PPA or "equivalent contracts" for projects located at Army installations and on non-installation property. This program could present an excellent opportunity for renewable energy developers -- provided they can meet the Department of Defense's government contracting rules. That's where we come in. Reed Smith has both the energy development and government contracts expertise to assist potential renewable energy bidders in the AEITF process.

You can find more details in our client alert and feel free to contact us for additional information.

Key Environmental and Safety Provisions in New Pennsylvania Gas Act

David Wagner — Mon, 12 Mar 2012 13:10:39 -0500

This post was written by Jennifer Smokelin

On February 14, 2012, Pennsylvania Governor Corbett signed House Bill 1950 into law as Act 13 of 2012, the Unconventional Gas Well Impact Fee Act (Act 13). This long bill (174 pages) provides for an impact fee, Oil and Gas Act (Title 58) amendments and local ordinance standards. We followed the legislative progression of the Act and, as promised, offer more detailed analysis of the environmental aspects of the Act here. In short, Act 13 provides for new well fees to be assessed on unconventional wells as well as restrictions on local government’s authority to impose burdens on oil and gas activities over and above those required by the state (which some municipalities are preparing to challenge). There are also new environmental and safety provisions for both surface and subsurface activities, some of which will be effective immediately while other will require a rulemaking by the Environmental Quality Board before becoming effective. This article discusses five significant “specifics” of the new environmental and safety provisions imposed by Act 13 and the implications on future permitting and operation of unconventional natural gas development.

The Act provides enhanced hydraulic fracturing chemical disclosure requirements – this is a new requirement.

Act 13 requires operators of unconventional wells to disclose hydraulic fracture fluids to the Chemical Disclosure Registry (which is a website developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission) which will make information about chemicals and additives available to the public in a fully searchable format. Act 13 provides, “Within 60 days following the conclusion of hydraulic fracturing, the operator of the well shall complete the chemical disclosure registry form and post the form on the chemical disclosure registry in accordance with regulations promulgated under this chapter in a format that does not link chemicals to their respective hydraulic fracturing additive” (section 3221.1) Specific information regarding chemicals claimed as trade secrets and proprietary information can be protected from disclosure. Further, certain “trace amounts” of chemicals need not be disclosed.

Act 13 also provides for enhanced well reporting requirements, including production data.

The implication of this provision on future operation of unconventional natural gas development is clearly to require operators to know and disclose hydraulic fracking fluids, even if those chemicals are being supplied by a vendor. Further, it is intended that the Registry be “fully searchable” by the Pennsylvania Department of Environmental Protection (DEP) and the public by geographic region on state wide bases. This could have liability implications in penalty and alleged contamination cases.

Producers must submit to DEP a report identifying and quantifying actual air contaminant emissions, with the report due by March 1 for air contaminant emissions during the preceding calendar year – this is a new requirement.

Section 3227 of Act 13 requires an owner or operator of a facility conducting natural gas operations in unconventional formations including development, production, transmission and processing to “submit to the [DEP] a source report identifying and quantifying actual air contaminant emissions from any air contamination source.” The reports under this section are due March 1 for the preceding year. Previously, on December 6, 2011, DEP alerted companies involved in unconventional natural gas development around Pennsylvania that they must submit to the department data on their facilities’ air emissions for 2011. The reports are due March 1, 2012. Details regarding the air emission inventory can be found here. It is unclear at this time whether and to what extent Act 13 changes or modifies the emission reporting requirements DEP notified regulated entities about in 2011.

Increased record keeping for transportation of waste water fluids – this is a revised requirement.

Under Act 13, producers are now required to maintain transportation records regarding the movement of wastewater In many ways, this is yet another move on the part of the legislature and DEP to discourage disposal of fracking wastewater and encourage on-site reuse. DEP’s preference for onsite reuse can also be seen in another provision of Act 13 where DEP can now deny permits for “failure to submit a water management plan that does not include a reuse plan for fluids that will be used to hydraulically fracture a well.” Therefore, the implication of these provisions on future operations of unconventional natural gas development is to look for future policies to further encourage reuse of wastewater.

Unconventional operators are presumed to be responsible for pollution of water supplies within 2,500 feet of the well bore when the pollution occurs within 12 months of the later of completion, drilling, stimulation or alteration of the well – this is a revised provision.

The Oil and Gas Act has always contained a rebuttable presumption of liability for pollution from gas wells. This rebuttable presumption was based on the distance of the well pad from the alleged pollution and the timing of the pollution event. Act 13 increases the distance of the rebuttal presumption of pollution from 1,000 feet to 2,500 feet from the water supply and the timing of such presumption is increased from six months to 12 months following the last drilling activity for unconventional drilling. The implication on future operation of unconventional natural gas development is an increase in an unconventional well operator’s window of presumed liability, both in distance and time.

Additional permitting and penalty provisions – this is a revised provision.

There are many permitting and penalty provisions in Act 13, including newly required notices to municipalities, as well as water management plans. Further, the Environmental Quality Board must issue regulations for DEP to use in evaluating: impact to public resources, for “ensuring optimal development of oil and gas resources” and respecting property rights of oil and gas owners. Further, aligning itself with other PA environmental statutes, the Oil and Gas Act now explicitly states that permits may be denied for continuing violations by an applicant’s parent or subsidiary. Also, Act 13 increases threefold the “not to exceed” ceiling for civil penalty assessment against unconventional well operators, and it is now up to $75,000. The implications on future permitting operations of unconventional natural gas development could be significant, and the EQB regulations will be something to watch for.

. . .

There are many other changes to the Oil and Gas Act under Act 13: bonding requirements, well siting and set-back provision changes, and well control emergency response - to name a few. This article serves to highlight five of the more significant measures. If you have questions with regard to other proposed changes (or the Act 13 changes listed here) please contact us.

In New Jersey, Solar Renewable Energy Credit Auction Prices Fall Below $200

David Wagner — Tue, 06 Mar 2012 18:22:37 -0500

This post was written by Henry King, Ferd Convery, Jim McGuire, and Marshall McLean

The fundamental question for the future of the New Jersey solar market is the impact of the recent decline in solar renewable energy credit (SREC) prices on development of new projects to meet New Jersey’s ambitious renewable portfolio standard (RPS) targets. The $600+ per SREC prices in 2010 and 2011 attracted a tremendous amount of development activity. Now, the decline in SREC prices and the unavailability of long-term SREC contracts have caused developers to question whether to continue to invest in New Jersey. The legislature has contemplated (but not approved) adjustments to the RPS system, including restrictions on large projects and increasing the RPS targets to increase demand. From our perspective, however, these proposed adjustments would not calm the market and encourage new development because of the fundamental uncertainty of the market-based system.

The four New Jersey electric distribution companies hold quarterly auctions to sell SRECs that they have procured from their solar programs. The auction is open to all market participants, including basic generation service and third-party suppliers that must comply with the New Jersey renewable portfolio standard requirements. The February 2012 SREC auction conducted by the four New Jersey electric distribution companies resulted in an auction price of $171.63 per SREC. The SRECs sold were generated between June 1, 2011 and December 31, 2011, which is in the 2012 Energy Year. A total of 26,488 SRECs were sold at this auction.

The $171.63 per SREC price is a decrease from the prior auction for 2012 Energy Year SRECs ($227.03 at the October 2011 auction), and a dramatic fall-off from the auctions for 2011 Energy Year SRECs ($669.01 at the October 2011 auction; $479.75 at the August 2011 auction; $475.00 at the July 2011 auction; and $669.69 at the April 2011 auction). Keep in mind that the decline in SREC prices at the latest auction was not unexpected. The auction price is about 25% lower than prices in short-term bi-lateral SREC contracts.

There is a lot of speculation about how the future of SREC prices, and the supply of SRECs will fall now that the federal 1603 cash grant in lieu of investment tax credit program has expired and SREC prices are lower. The loss of the 1603 cash grant program will especially hurt smaller developers that may not have access to tax equity financing, and smaller projects that can’t bear the transaction costs.

The impact of the loss of the 1603 cash grant program and low SREC prices should eventually slow the supply of SRECs in the New Jersey market. In theory, this should cause a rise in SREC prices since the demand for SRECs under the RPS will continue to grow. Whether higher SREC prices will attract solar development is not clear, however, since many developers have now lived through the ongoing decline in prices and may only return once SREC prices are not subject to such dramatic swings.